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 March 31, 2013

OR

(  ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________

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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large		Non-	Smaller
	accelerated	Accelerated	accelerated	reporting
	filer	filer	filer	company
DPL Inc.	o	o	x	o
The Dayton Power and Light Company	o	o	x	o

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

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

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

As of March 31, 2013, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding
DPL  Inc.	Common Stock, no par value	1
The Dayton Power and Light Company	Common Stock, $0.01 par value	41,172,173

Documents incorporated by reference:  None

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

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DPL Inc. and The Dayton Power and Light Company

Index to Quarterly Report on Form 10-Q

Quarter Ended March 31, 2013

Glossary of Terms		5
Part I  Financial Information
Item 1	Financial Statements – DPL Inc. and The Dayton Power and Light Company (Unaudited)
	DPL Inc.
	Condensed Consolidated Statements of Operations	12
	Condensed Consolidated Statements of ComprehensiveIncome(Loss)	13
	Condensed Consolidated Statements of Cash Flows	14
	Condensed Consolidated Balance Sheets	16
	Notes to Condensed Consolidated Financial Statements	18
	The Dayton Power and Light Company
	Condensed Statements of Results of Operations	50
	Condensed Statements of Comprehensive Income (Loss)	51
	Condensed Statements of Cash Flows	52
	Condensed Balance Sheets	54
	Notes to Condensed Financial Statements	56
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	83
	Electric Sales and Revenues	109
Item 3	Quantitative and Qualitative Disclosures about Market Risk	109
Item 4	Controls and Procedures	109

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DPL Inc. and The Dayton Power and Light Company

Index to Quarterly Report on Form 10-Q (cont.)

Part II  Other Information
Item 1	Legal Proceedings	110
Item 1A	Risk Factors	110
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	111
Item 3	Defaults Upon Senior Securities	111
Item 4	Mine Safety Disclosures	111
Item 5	Other Information	111
Item 6	Exhibits	112
Other
Signatures		114

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GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
AES	The AES Corporation, a global power company, the ultimate parent company of DPL
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
CFTC	Commodity Futures Trading Commission
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CO2	Carbon Dioxide
CCEM	Customer Conservation and Energy Management
ComEd	Commonwealth Edison Company, a unit of Chicago-based Exelon Corporation
CRES	Competitive Retail Electric Service
CSAPR	Cross-State Air Pollution Rule
DPL	DPL Inc.
DPLE	DPL Energy, LLC, a wholly owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales
DPLER	DPL Energy Resources, Inc., a wholly owned subsidiary of DPL which sells competitive electric energy and other energy services
DP&L	The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio
Duke Energy	Duke Energy Ohio, Inc., formerly The Cincinnati Gas & Electric Company (CG&E)
EBITDA	Earnings before interest, taxes, depreciation and amortization
EGU	Electric generating unit
ESP	Electric Security Plans filed with the PUCO, pursuant to Ohio law
2009 ESP Stipulation	A Stipulation and Recommendation filed by DP&L with the PUCO on February 24, 2009 regarding DP&L’s ESP filing pursuant to SB 221.  The Stipulation was signed by the Staff of the PUCO, the Office of the Ohio Consumers’ Counsel and various intervening parties.  The PUCO approved the Stipulation on June 24, 2009.
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
Form 10-K	DPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, 2012, which was filed on February 26, 2013

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GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym	Definition
FTRs	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
IFRS	International Financial Reporting Standards
kWh	Kilowatt hours
Master Trust	DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans.
MATS	Mercury and Air Toxics Standards
MC Squared	MC Squared Energy Services, LLC, a retail electricity supplier wholly owned by DPLER
Merger	The merger of DPL and Dolphin Sub, Inc., a whollyowned subsidiary of AES, in accordance with the terms of the Merger agreement.  At the Merger date, Dolphin Sub, Inc. was merged into DPL, leaving DPL as the surviving company.  As a result of the Merger, DPL became a whollyowned subsidiary of AES.
Merger agreement	The Agreement and Plan of Merger dated April 19, 2011 among DPL, AES,  and Dolphin Sub, Inc., a wholly owned subsidiary of AES, whereby AES agreed to acquire DPL for $30 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of existing debt.  Upon closing, DPL became a wholly owned subsidiary of AES.
Merger date	November 28, 2011, the date of the closing of the Merger
MRO	Market Rate Option, a plan available to be filed with the PUCO pursuant to Ohio law
MTM	Mark to Market
MVIC	Miami Valley Insurance Company, a wholly owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies related to jointly owned facilities operated by DP&L
NERC	North American Electric Reliability Corporation
Non-bypassable	Charges that are assessed to all customers regardless of whom the customer selects to supply its retail electric service
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NSR	New Source Review – a preconstruction permitting program regulating new or significantly modified sources of air pollution
NYMEX	New York Mercantile Exchange
OAQDA	Ohio Air Quality Development Authority
Ohio EPA	Ohio Environmental Protection Agency
Ohio Power	Ohio Power Company, a subsidiary of American Electric Power Company, Inc. (“AEP”).  Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011.
OTC	Over-The-Counter
OVEC	Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest

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GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym	Definition
PJM	PJM Interconnection, LLC, anRTO
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
RPM	Reliability Pricing Model.  The Reliability Pricing Model is PJM’s capacity construct.  The purpose of the RPM is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint.  Under the RPM construct, PJM procures capacity, through a multi-auction structure, on behalf of the load serving entities to satisfy the load obligations.  There are three RPM auctions held for each delivery year (running from June 1 through May 31).  The base residual auction is held three years in advance of the delivery year and then there is one incremental auction held in each of the subsequent three years.  DP&L’s capacity is located in the “rest of” RTO area of PJM.
RTO	Regional Transmission Organization
SB 221	Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008.  This law required all Ohio distribution utilities to file either an ESP or MRO to be in effect January 1, 2009.  The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SIP	AState Implementation Plan(SIP) is aUnited Statesstate plan for complying with the federalCAA, administered by theUSEPA. The SIP consists of narrative, rules, technical documentation and agreements that an individual state will use to clean up polluted areas.
SO2	Sulfur Dioxide
SO3	Sulfur Trioxide
SSO	Standard Service Offer which represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers within DP&L’s service territory
TCRR	Transmission Cost Recovery Rider
USEPA	U.S. Environmental Protection Agency
USF	Universal Service Fund
VRDN	Variable Rate Demand Note

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This report includes the combined filing of DPL and DP&L.On November 28, 2011, DPL became a wholly owned subsidiary of AES, a global power company.  Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise.  Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section. 

FORWARD-LOOKING STATEMENTS

Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.  Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial position and other similar matters constitute forward-looking statements.  Forward-looking statements are based on management’s beliefs, assumptions and expectations of future economic performance, taking into account the information currently available to management.  These statements are not statements of historical fact and are typically identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will” and similar expressions.  Such forward-looking statements are subject to risks and uncertainties and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to:

· abnormal or severe weather and catastrophic weather-related damage;

· unusual maintenance or repair requirements;

· changes in fuel costs and purchased power, coal, environmental emissions, natural gas and other commodity prices;

· volatility and changes in markets for electricity and other energy-related commodities;

· increased competition and deregulation in the electric utility industry;

· generating unit availability and capacity;

· transmission and distribution system reliability and capacity;

· increased competition in the retail generation market;

· impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;

· changes in interest rates;

· changes in our credit ratings or the credit ratings of AES;

· state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws;

· changes in environmental laws and regulations to which DPL and its subsidiaries are subject;

· the development and operation of RTOs, including PJM to which DP&L has given control of its transmission functions;

· changes in our purchasing processes, pricing, delays, contractor and supplier performance and availability;

· significant delays associated with large construction projects;

· growth in our service territory and changes in demand and demographic patterns;

· changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

· financial market conditions;

· the outcomes of litigation and regulatory investigations, proceedings or inquiries;

· general economic conditions;

· costs related to the Merger and the effects of any disruption from the Merger that may make it more difficult to maintain relationships with employees, customers, other business partners or government entities and;

· the risks and other factors discussed in this report and other DPL and DP&L filings with the SEC. 

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

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statement is based.  If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results and many are beyond our control. See “Risk Factors” for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook.

You may read and copy any document we file at the SEC’s public reference room located at 100 F Street N.E., Washington, D.C. 20549, USA.  Please call the SEC at (800) SEC-0330 for further information on the public reference room.  Our SEC filings are also available to the public from the SEC’s website at http://www.sec.gov.

COMPANY WEBSITES

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

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Part I – Financial Information

This report includes the combined filing of DPL and DP&L.  Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise.  Discussions or areas of this report that apply only to DPL or DP&L will be clearly noted in the section.

Item 1 – Financial Statements

9

FINANCIAL STATEMENTS

DPL INC.

10

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS
	Three months ended March 31,
$ in millions	2013		2012
Revenues	$	394.6	$	434.0
Cost of revenues:
Fuel		88.6		97.4
Purchased power		95.3		94.8
Amortization of intangibles		1.8		27.8
Total cost of revenues		185.7		220.0
Gross margin		208.9		214.0
Operating expenses:
Operation and maintenance		99.2		101.7
Depreciation and amortization		31.8		31.4
General taxes		21.0		21.7
Total operating expenses		152.0		154.8
Operating income		56.9		59.2
Other income / (expense), net:
Investment income		0.1		0.1
Interest expense		(30.5)		(29.6)
Other expense		(0.6)		(0.3)
Total other income / (expense), net		(31.0)		(29.8)
Earnings before income taxes		25.9		29.4
Income tax expense		6.0		7.7
Net income	$	19.9	$	21.7
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

11

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three months ended March 31,
$ in millions	2013		2012
Net income	$	19.9	$	21.7
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax expense of $(0.1) and $(0.2) for each respective period		0.2		0.4
Reclassification to earnings, net of income tax expense of $0.0 and $0.0 for each respective period		0.1		-
Total change in fair value of available-for-sale securities		0.3		0.4
Derivative activity:
Change in derivative fair value, net of income tax expense of $(1.1) and $(4.2) for each respective period		1.2		7.6
Reclassification to earnings, net of income tax (expense) / benefit of $(0.1) and $0.6 for each respective period		0.2		(0.9)
Total change in fair value of derivatives		1.4		6.7
Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $(0.3) and $0.0 for each respective period		0.3		-
Total change in unfunded pension obligation		0.3		-
Other comprehensive income		2.0		7.1
Net comprehensive income	$	21.9	$	28.8
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three months ended March 31,
$ in millions	2013		2012
Cash flows from operating activities:
Net income	$	19.9	$	21.7
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization		31.8		31.4
Amortization of intangibles		1.8		27.8
Amortization of debt market value adjustments		(4.8)		(4.7)
Deferred income taxes		23.3		(9.2)
Changes in certain assets and liabilities:
Accounts receivable		19.5		(3.4)
Inventories		(4.4)		(0.6)
Taxes applicable to subsequent years		17.2		22.9
Deferred regulatory costs, net		3.6		7.2
Accounts payable		2.7		(1.8)
Accrued taxes payable		(33.7)		(21.6)
Accrued interest payable		23.7		29.1
Pension, retiree and other benefits		3.2		2.1
Insurance and claims costs		1.0		0.8
Other		1.4		2.3
Net cash from operating activities		106.2		104.0
Cash flows from investing activities:
Capital expenditures		(33.8)		(54.0)
Purchase of renewable energy credits		(0.5)		(0.7)
Increase in restricted cash		(12.7)		(8.7)
Net cash used for investing activities		(47.0)		(63.4)

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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (cont.)
	Three months ended March 31,
$ in millions	2013		2012
Net cash from financing activities:
Dividends paid on common stock		-		(45.0)
Contributions to additional paid-in capital from parent		-		2.0
Payment to former warrant holders		-		(9.0)
Net cash from financing activities		-		(52.0)
Cash and cash equivalents:
Net change		59.2		(11.4)
Balance at beginning of period		192.1		173.5
Cash and cash equivalents at end of period	$	251.3	$	162.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	11.3	$	5.7
Income taxes paid/(refund), net	$	(20.0)	$	7.0
Non-cash financing and investing activities:
Accruals for capital expenditures	$	10.6	$	24.1
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

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DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	At		At
	March 31,		December 31,
$ in millions	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	251.3	$	192.1
Restricted cash		23.4		10.7
Accounts receivable, net (Note 2)		190.1		208.2
Inventories (Note 2)		114.5		110.1
Taxes applicable to subsequent years		52.1		69.3
Regulatory assets, current (Note 3)		18.0		21.1
Other prepayments and current assets		43.0		43.1
Total current assets		692.4		654.6
Property, plant & equipment:
Property, plant & equipment		2,625.7		2,590.4
Less: Accumulated depreciation and amortization		(134.6)		(115.9)
		2,491.1		2,474.5
Construction work in process		70.9		89.3
Total net property, plant & equipment		2,562.0		2,563.8
Other noncurrent assets:
Regulatory assets, non-current (Note 3)		180.9		185.5
Goodwill		759.1		759.1
Intangible assets, net of amortization		50.0		50.1
Other deferred assets		29.9		34.2
Total other noncurrent assets		1,019.9		1,028.9
Total assets	$	4,274.3	$	4,247.3
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

15

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	At		At
	March 31,		December 31,
$ in millions	2013		2012
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Current portion - long-term debt (Note 5)	$	580.1	$	584.9
Accounts payable		80.8		83.2
Accrued taxes		63.5		97.1
Accrued interest		55.5		31.8
Customer security deposits		14.7		15.0
Regulatory liabilities, current (Note 3)		-		0.1
Insurance and claims costs		12.5		11.5
Other current liabilities		86.3		96.9
Total current liabilities		893.4		920.5
Noncurrent liabilities:
Long-term debt (Note 5)		2,025.0		2,025.0
Deferred taxes (Note 6)		558.2		534.9
Taxes payable		68.1		68.1
Regulatory liabilities, non-current (Note 3)		118.8		117.3
Pension, retiree and other benefits		63.2		61.6
Unamortized investment tax credit		3.1		3.3
Other deferred credits		71.5		71.4
Total noncurrent liabilities		2,907.9		2,881.6
Redeemable preferred stock of subsidiary		18.4		18.4
Commitments and contingencies (Note 10)
Common shareholder's equity:
Common stock:
1,500 shares authorized; 1 share issued and outstanding at March 31, 2013 and December 31, 2012
Other paid-in capital		2,236.7		2,236.7
Accumulated other comprehensive loss		(1.9)		(3.9)
Retained deficit		(1,780.2)		(1,806.0)
Total common shareholder's equity		454.6		426.8
Total liabilities and shareholder's equity	$	4,274.3	$	4,247.3
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

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DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1.  Overview and Summary of Significant Accounting Policies

Description of Business  

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio.  DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared.  Refer to Note 11 for more information relating to these reportable segments.  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.   

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

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers.  DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011.  DPLER has approximately 247,000 customers currently located throughout Ohio and Illinois.  DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations.  DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves. 

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

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

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

DPL and its subsidiaries employed 1,475 people as of March 31, 2013, of which 1,412 employees were employed by DP&L.  Approximately 53% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014. 

Financial Statement Presentation  

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP.  DP&L’s undivided ownership interests in certain coal-fired generating facilities and numerous transmission facilities are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date for DPL.  Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statement of Operations.  See Note 4 for more information. 

All material intercompany accounts and transactions are eliminated in consolidation.   

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X.  Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report.  Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.   

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In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2013; our results of operations for the three months ended March 31, 2013 and 2012 and our cash flows for the three months ended March 31, 2013 and 2012.  Unless otherwise noted, all adjustments are normal and recurring in nature.  Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013. 

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

Goodwill Impairment

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

Sale of Receivables 

In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy.  These sales are at face value for cash at the amounts billed for DPLER customers’ use of energy.  Total receivables sold to Duke Energy during the three months ended March 31, 2013 and 2012 were $4.5 million and $2.0 million, respectively.  Similarly, MC Squared sells receivables from their customers in ComEd territory to ComEd.  Total receivables sold to ComEd during the three months ended March 31, 2013 and 2012 were $16.9 million and $0.0million, respectively.  There is no recourse or any other continuing involvement associated with the sold receivables.

Property, Plant and Equipment  

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment.  Property, plant and equipment are stated at cost.  For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC).  AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects.  For non-regulated property including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. 

Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.  The total AFUDC and capitalized interest was $0.3 million and $1.4 million during the three months ended March 31, 2013 and 2012, respectively.  

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

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

Intangibles 

Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP.  Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances.  In addition, we recorded emission allowances at their fair value as of the Merger date.  Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.  During the three months ended March 31, 2013 and 2012, DPL had no gains from the sale of emission allowances.   

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

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities 

DPL collects certain excise taxes levied by state or local governments from its customers.  These taxes are accounted for on a net basis and recorded as a reduction in revenues.  The amounts for the three months ended March 31, 2013 and 2012 were $13.4 million and $12.9 million, respectively. 

Recently Issued Accounting Standards 

Offsetting Assets and Liabilities

The FASB recently issued ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”to limit the scope of ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” to derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions.  This ASU is effective for annual and interim periods beginning on or after January 1, 2013.  The FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220):  Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards  

Offsetting Assets and Liabilities 

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

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Testing Indefinite-Lived Intangible Assets for Impairments 

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012.  We adopted this ASU on January 1, 2013.  This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.”  ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30.  This rule did not have a material effect on our overall results of operations, financial position or cash flows. 

2. Supplemental Financial Information 

Accounts receivable and Inventories are as follows at March 31, 2013 and December 31, 2012:

	At		At
	March 31,		December 31,
$ in millions	2013		2012
Accounts receivable, net:
Unbilled revenue	$	65.3	$	75.2
Customer receivables		107.5		98.2
Amounts due from partners in jointly owned plants		15.3		19.7
Coal sales		-		1.6
Other		3.1		14.6
Provision for uncollectible accounts		(1.1)		(1.1)
Total accounts receivable, net	$	190.1	$	208.2
Inventories, at average cost:
Fuel and limestone	$	72.0	$	67.3
Plant materials and supplies		40.6		41.0
Other		1.9		1.8
Total inventories, at average cost	$	114.5	$	110.1

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Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months ended March 31, 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statement of Operations	Three months ended March 31,
$ in millions		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.1
	Total before income taxes		0.1
	Tax expense		-
	Net of income taxes		0.1
Gains and losses on cash flow hedges: (Note 9)
	Revenue		(0.5)
	Purchased power		0.8
	Total before income taxes		0.3
	Tax expense		(0.1)
	Net of income taxes		0.2
Amortization of defined benefit pension items: (Note 7)
	Reclassification to Other income / (deductions)		-
	Prior service cost for the period (1)		-
	Net loss for the period (1)		-
	Total before income taxes		-
	Tax benefit		0.3
	Net of income taxes		0.3
Total reclassifications for the period, net of income taxes		$	0.6

(1)   These Accumulated Other Comprehensive Income / (Loss) components are included in the computation of net periodic pension costs (See Note 7 for additional information).

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2013 are as follows:

$ in millions	Gains / (losses) on Available-for-sale securities		Gains / (losses) on Cash Flow Hedges		Change in Unfunded Pension Obligation		Total
Balance January 1, 2013	$	0.4	$	(2.5)	$	(1.8)	$	(3.9)
Other comprehensive income before reclassifications		0.2		1.2		-		1.4
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1		0.2		0.3		0.6
Net current period other comprehensive income		0.3		1.4		0.3		2.0
Balance March 31, 2013	$	0.7	$	(1.1)	$	(1.5)	$	(1.9)

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3.  Regulatory Assets and Liabilities 

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

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

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

Regulatory assets and liabilities for DPL are as follows:  

$ in millions	Type of Recovery (a)	Amortization through	At March 31, 2013		At December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	6.6	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		11.4		14.1
Total regulatory assets, current			$	18.0	$	21.1
Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	34.3	$	35.1
Pension benefits	C	Ongoing		87.3		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.7		11.9
Regional transmission organization costs	D	2014		2.2		2.6
Deferred storm costs	D			24.7		24.4
CCEM smart grid and advanced metering infrastructure costs	D			6.6		6.6
CCEM energy efficiency program costs	F	Ongoing		3.4		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.6		4.7
Total regulatory assets, non-current			$	180.9	$	185.5
Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.6	$	112.1
Postretirement benefits				4.8		5.0
Other				0.4		0.2
Total regulatory liabilities, non-current			$	118.8	$	117.3

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

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

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

F – Recovery of incurred costs plus rate of return. 

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Regulatory Assets 

TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM.  On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.   

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider.  The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter.  DP&L implemented the fuel and purchased power recovery rider on January 1, 2010.  As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process.  

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

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

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

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

Deferred storm costs relate to costs incurred to repair the damage caused by storms in the following years:

· 2008 – related to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other 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.

· 2011 – related to five major storms in 2011.  On December 21, 2012, DP&L filed a request with the PUCO for an accounting order to defer costs and a request for recovery of costs associated with these storms.  At March 31, 2013, DP&L believes the recovery of these costs is probable.

· 2012 – related to storm damage that occurred during the final weekend of June 2012.  On August 10, 2012, DP&L filed a request with the PUCO, which was modified on October 19, 2012, for an accounting order to defer the costs associated with this storm damage.  On December 19, 2012, the PUCO issued an order permitting partial deferral. 

On December 21, 2012, DP&L filed a request for recovery of all of these deferred storm costs with the PUCO.

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 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. 

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On April 29, 2011, DP&L filed to true-up the energy efficiency rider which was approved by the PUCO on October 18, 2011.  DP&Lmade its true-up filing on April 30, 2013.

Consumer education campaign represents costs for consumer education advertising regarding electric deregulation.  DP&L will be seeking recovery of these costs as part of our next distribution rate case filing at the PUCO.  The timing of such a filing has not yet been determined. 

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

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

Regulatory Liabilities 

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

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

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities with certain other Ohio utilities.  Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on the energy taken.  The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  As of March 31, 2013,  DP&L had $39.0 million of construction work in process at such jointly owned facilities.  DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets.  Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned units and stations. 

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DP&L’s undivided ownership interest in such facilities as well as our wholly owned coal-fired Hutchings Station at March 31, 2013 is as follows: 

	DP&L Share			DP&L Investment
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)	Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Beckjord Unit 6	50.0	207	$	1	$	1	$	-	No
Conesville Unit 4	16.5	129		42		4		12	Yes
East Bend Station	31.0	186		8		3		3	Yes
Killen Station	67.0	402		301		4		9	Yes
Miami Fort Units 7 and 8	36.0	368		212		9		3	Yes
Stuart Station	35.0	808		202		7		10	Yes
Zimmer Station	28.1	365		169		15		2	Yes
Transmission (at varying percentages)		n/a		40		2		-
Total		2,465	$	975	$	45	$	39
Wholly owned production station:
Hutchings Station	100.0	365	$	-	$	-	$	-	No

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

DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated on June 1, 2013.  In addition, DP&L has notified PJM that the remaining coal-fired units at Hutchings Station will be deactivated on June 1, 2015.  The decision to deactivate these remaining coal-fired units has been made because these units are not equipped with the advanced environmental control technologies needed to comply with the MATS, and the expected cost of compliance with MATS for these units would exceed the expected return.  Additionally, conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return.

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

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5.  Debt Obligations 

Long-term debt

$ in millions	March 31, 2013		December 31, 2012
Pollution control series maturing in January 2028 - 4.7%	$	36.1	$	36.1
Pollution control series maturing in January 2034 - 4.8%		179.6		179.6
Pollution control series maturing in September 2036 - 4.8%		96.3		96.3
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligations		0.1		0.1
Total long-term debt at subsidiary		330.4		330.4
Bank term loan-maturing in August 2014 - variable rates: 2.46% - 2.47% and 2.22% - 2.47% (a)		425.0		425.0
Senior unsecured bonds maturing October 2016 - 6.5%		450.0		450.0
Senior unsecured bonds maturing October 2021 - 7.3%		800.0		800.0
Note to DPL Capital Trust II maturing in September 2031 - 8.125%		19.6		19.6
Total non-current portion - long-term debt - DPL	$	2,025.0	$	2,025.0

Current portion of long-term debt 

$ in millions	March 31, 2013		December 31, 2012
First mortgage bonds maturing in October 2013 - 5.125%	$	479.7	$	484.5
Pollution control series maturing in November 2040 - variable rates: 0.10% - 0.16% and 0.04% - 0.26% (a)		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.3		0.3
Total current portion - long-term debt - DPL	$	580.1	$	584.9

(a)  Range of interest rates for the three months ended March 31, 2013 and the twelve months ended December 31, 2012, respectively. 

At March 31, 2013, maturities of long-term debt, including capital lease obligations, are as follows:

$ in millions
Due within one year	$	570.4
Due within two years		425.2
Due within three years		0.1
Due within four years		450.1
Due within five years		0.2
Thereafter		1,152.8
Total maturities		2,598.8
Unamortized premiums and discounts		6.3
Total long-term debt	$	2,605.1

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

On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040.  In turn, DP&L borrowed these funds from the OAQDA and

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issued corresponding First Mortgage Bonds to support repayment of the funds.  The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A.  This standby letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses.  If the standby letter of credit expires, this would trigger a mandatory tender of all of the outstanding bonds, therefore, we have reflected these outstanding bonds as a current liability.  DP&L is currently working to refinance this standby letter of credit.  Though not yet finalized it is expected that the new facility will be for three to five years under terms that are substantially similar to those of the existing facility. We currently have secured all of the bank commitments necessary to extend this facility and intend to finalize the amendment during the second quarter of 2013.  Fees associated with this standby letter of credit facility were not material during the three months ended March 31, 2013 and 2012.   

On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  The agreement provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.This agreement, originally for a three year term expiring on April 20, 2013, was extended through May 31, 2013 by an amendment dated April 11, 2013.  DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013, DP&L had no outstanding letters of credit against this facility.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013, DP&L had no outstanding letters of credit against this facility. 

Prior to the expiration of the DP&L amended revolving credit facility (that is now scheduled to expire on May 31, 2013) and in no case later than the end of the second quarter of 2013, DP&L intends to enter into a new $275.0 million to $350.0 million revolving credit facility and to extinguish both of the existing DP&L revolving credit facilities discussed above. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing.  The terms and conditions of this new revolving credit facility have not been finalized, but it is expected that they will be substantially similar to those of the existing DP&L revolving credit facilities.  As of the date of filing of this quarterly report on Form 10-Q, DP&L has the bank commitments required to close the new DP&L revolving credit facility.

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

On August 24, 2011, DPL entered into a $125.0 million unsecured revolving credit agreement with a syndicated bank group.  This agreement is for a three year term expiring on August 24, 2014.  The size of the facility was reduced from $125.0 million to $75.0 million as part of an amendment dated October 19, 2012 that was negotiated between DPL and the syndicated bank group.  DPL had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility may also be used to issue letters of credit up to the $75.0 million limit.  As of March 31, 2013, DPL had no outstanding letters of credit against this facility.   

On August 24, 2011, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group.  This agreement is for a three year term expiring on August 24, 2014.DPL has borrowed the entire $425.0 million available under the facility at March 31, 2013 and December 31, 2012.  Fees associated with this term loan were not material during the three months ended March 31, 2013 and 2012. 

Prior to the end of the second quarter, DPL intends to enter into a new $75.0 million to $150.0 million revolving credit facility and to extinguish the existing $75.0 million facility. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing. Contemporaneously, DPL intends to refinance a portion of its $425.0 million term loan, and repay the balance of the currently outstanding term loan with cash.  The terms and conditions of this new revolving credit facility and new term loan have not been finalized, but it is expected they will be at market for these types of transactions.  As of the date of filing

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this quarterly report on Form 10-Q, DPL has secured all of the bank commitments required to close the new DPL revolving credit facility and the new DPL term loan.

DPL’s unsecured revolving credit agreement and DPL’s unsecured term loan each have two financial covenants, one of which was changed as part of amendments dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups.  The first financial covenant, originally a Total Debt to Capitalization ratio, was changed, effective September 30, 2012, to a Total Debt to EBITDA ratio.  The Total Debt to EBITDA ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters.   

The second financial covenant is an EBITDA to Interest Expense ratio.  The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.   

The amendments, dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups, restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities.

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

Substantially all property, plant and equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage, dated October 1, 1935, with the Bank of New York Mellon as Trustee.  DP&L filed for approval to refinance the $470.0 million of first mortgage bonds maturing in October 2013 with the PUCO on April 12, 2013.  Subsequent to the receipt of this approval and no later than the end of the third quarter of 2013, DP&L intends to refinance these bonds.

6.  Income Taxes 

The following table details the effective tax rates for the three months ended March 31, 2013 and 2012. 

	Three months ended March 31,
	2013	2012
DPL	23.2%	26.0%

Income tax expense for the three months ended March 31, 2013 and 2012 was calculated using the estimated annual effective income tax rates for 2013 and 2012 of 30.2% and 25.6%, respectively.  Management estimates the annual effective tax rate based on its forecast of annual pre-tax income.  To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

For the three months ended March 31, 2013, DPL’s current period effective rate is less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 IRS examination in the first quarter of 2013.  The decrease in the effective rate compared to the same period in 2012 is also primarily due to the resolution of the 2008 IRS examination.

Deferred tax liabilities for DPL increased by approximately $23.3 million during the three months ended March 31, 2013 primarily related to the resolution of the 2008 IRS examination. 

The IRS began an examination of our 2008 Federal income tax return during the second quarter of 2010.  The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013.  As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense.

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7.  Pension and Postretirement Benefits 

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

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three months ended March 31, 2013 or 2012. 

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

The net periodic benefit cost/(income) of the pension and postretirement benefit plans for the three months ended March 31, 2013 and 2012 was: 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended March 31,		Three months ended March 31,		Three months ended March 31,		Three months ended March 31,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	0.1	$	0.1
Interest cost		3.9		4.3		0.2		0.3
Expected return on assets (a)		(5.9)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		1.2		1.2		(0.1)		(0.2)
Prior service cost		0.4		0.4		-		-
Net periodic benefit cost / (income)	$	1.4	$	1.7	$	0.1	$	0.1

(a)   For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $336.0 million, respectively. 

Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated Future Benefit Payments and Medicare Part D Reimbursements
$ in millions	Pension		Postretirement
2013	$	16.6	$	1.7
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		124.4		6.8

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 value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future. 

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The following table presents the fair value and cost of our non-derivative instruments at March 31, 2013 and December 31, 2012.  See also Note 9 for the fair values of our derivative instruments. 

	At March 31,				At December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities		4.0		5.7		4.0		5.1
Debt Securities		4.5		4.9		4.6		5.0
Multi-Strategy Fund		0.3		0.3		0.3		0.3
Total Assets	$	9.0	$	11.1	$	9.1	$	10.6
Liabilities
Debt	$	2,605.1	$	2,705.4	$	2,609.9	$	2,707.1

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Consolidated Balance Sheet at their gross fair value, except for Debt which is presented at amortized cost.

Debt 

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

Master Trust Assets 

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

DPL had $1.2 million ($0.8million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2013 and $0.7 million ($0.5 million after tax) of unrealized gains immaterial unrealized losses in AOCI at December 31, 2012. 

$0.1 million ($0.1 million after tax) of various investments were sold during the quarter to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  

Net Asset Value (NAV) per Unit 

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of March 31, 2013 and December 31, 2012.  These assets are part of the Master Trust.  Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date.  Investments that have restrictions on the redemption of the investments are Level 3 inputs.  As of March 31, 2013, DPL did not have any investments for sale at a price different from the NAV per unit. 

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Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at March 31, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	-	Immediate
Equity Securities (b)		5.7		5.1		-	Immediate
Debt Securities (c)		4.9		5.0		-	Immediate
Multi-Strategy Fund (d)		0.3		0.3		-	Immediate
Total	$	11.1	$	10.6	$	-

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

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

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

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

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The fair value of assets and liabilities at March 31, 2013 and December 31, 2012 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows: 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.7		-		5.7		-
Debt Securities		4.9		-		4.9		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		11.1		0.2		10.9		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		5.8		-		5.8		-
Total Derivative Assets		6.0		0.2		5.8		-
Total Assets	$	17.1	$	0.4	$	16.7	$	-
Liabilities
Derivative Liabilities
Interest Rate Hedge	$	23.2	$	-	$	23.2	$	-
Forward Power Contracts		23.3		-		23.3		-
Total Derivative Liabilities		46.5		-		46.5		-
Long-term Debt		2,705.4		-		2,686.6		18.8
Total Liabilities	$	2,751.9	$	-	$	2,733.1	$	18.8

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Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.3		-		6.3		-
Total Derivative Assets		6.5		0.2		6.3		-
Total Assets	$	17.1	$	0.4	$	16.7	$	-
Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Interest Rate Hedge		29.5		-		29.5		-
Forward Power Contracts		13.1		-		13.1		-
Total Derivative Liabilities		42.7		-		42.6		0.1
Long-term debt		2,707.1		-		2,688.2		18.9
Total Liabilities	$	2,749.8	$	-	$	2,730.8	$	19.0

We use the market approach to value our financial instruments.  Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents.  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 forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market).  Other Level 2 assets include:  open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit; and interest rate hedges, which use observable inputs to populate a pricing model.  Financial transmission rights are considered a Level 3 input because the monthly auctions are considered inactive. 

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

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

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

Non-recurring Fair Value Measurements 

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

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management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  Additions to AROs were not material during the three months ended March 31, 2013 and 2012. 

Cash Equivalents 

DPL had $175.0 million and $130.0 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012, respectively.  The money market funds have quoted prices that are generally equivalent to par and are considered Level 1.

9.  Derivative Instruments and Hedging Activities 

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

At March 31, 2013, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		2.8		-		2.8
Heating Oil Futures		Mark to Market	Gallons		1,890.0		-		1,890.0
Forward Power Contracts		Cash Flow Hedge	MWh		842.6		(2,040.9)		(1,198.3)
Forward Power Contracts		Mark to Market	MWh		2,221.4		(7,069.8)		(4,848.4)
Interest Rate Swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

At December 31, 2012, DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating Oil Futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward Power Contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward Power Contracts		Mark to Market	MWh		2,510.7		(4,760.4)		(2,249.7)
Interest Rate Swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

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 is determined by observable market prices available as of the balance sheet dates and will continue to fluctuate with changes in market prices up to contract expiration.  The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring.  The ineffective portion of the cash flow hedge is recognized in earnings in the current period.  All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. 

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. 

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We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt.  Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  We do not hedge all interest rate exposure.  We reclassify gains and losses on interest rate derivative hedges related to debt financings from AOCI into earnings in those periods in which hedged interest payments occur.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2013 and 2012: 

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(3.0)	$	0.5	$	0.3	$	(0.8)
Net gains / (losses) associated with current period hedging transactions		(2.9)		4.1		(1.5)		9.1
Net gains reclassified to earnings
Interest Expense		-		-		-		0.2
Revenues		(0.3)		-		(1.2)		-
Purchased Power		0.5		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	(5.7)	$	4.6	$	(2.3)	$	8.5
Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest Expense	$	-	$	-	$	-	$	(1.6)
Revenues	$	-	$	-	$	-	$	-
Purchased Power	$	-	$	-	$	-	$	-
Portion expected to be reclassified to earnings in the next twelve months (a)	$	9.9	$	-
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21		5

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

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.  FTRs, heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts are currently marked to market. 

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 and are recognized in the Condensed Consolidated Statements of Results of Operations on an accrual basis. 

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Regulatory Assets and Liabilities 

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

The following tables show the amount and classification within the Condensed Consolidated Statements of Results of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three months ended March 31, 2013 and 2012. 

For the three months ended March 31, 2013
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	-	$	-	$	-	$	(16.5)	$	(16.5)
Realized gain / (loss)		-		-		0.5		0.4		0.9
Total	$	-	$	-	$	0.5	$	(16.1)	$	(15.6)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	-	$	-	$	-	$	-	$	-
Regulatory (asset) / liability		-		-		-		-		-
Recorded in Income Statement:  gain / (loss)
Revenue		-		-		-		-		-
Purchased Power		-		-		0.5		(16.1)		(15.6)
Fuel		-		-		-		-		-
O&M		-		-		-		-		-
Total	$	-	$	-	$	0.5	$	(16.1)	$	(15.6)

For the three months ended March 31, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(7.8)	$	(0.1)	$	(0.1)	$	1.4	$	(6.6)
Realized gain / (loss)		(5.0)		0.9		(0.2)		(2.3)		(6.6)
Total	$	(12.8)	$	0.8	$	(0.3)	$	(0.9)	$	(13.2)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	(3.5)	$	-	$	-	$	-	$	(3.5)
Regulatory (asset) / liability		(1.1)		0.1		-		-		(1.0)
Recorded in Income Statement:  gain / (loss)
Revenue		-		-		-		3.4		3.4
Purchased Power		-		-		(0.3)		(4.3)		(4.6)
Fuel		(8.2)		0.6		-		-		(7.6)
O&M		-		0.1		-		-		0.1
Total	$	(12.8)	$	0.8	$	(0.3)	$	(0.9)	$	(13.2)

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DPL has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.  The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.  The following table shows the fair value and balance sheet classification of DPL’s derivative instruments at March 31, 2013: 

Fair Values of Derivative Instruments
at March 31, 2013
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.2	$	(0.1)	$	-	$	0.1
Forward Power Contracts	MTM		4.5		(3.8)		-		0.7
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	MTM		1.1		(0.6)		-		0.5
Total assets		$	6.0	$	(4.5)	$	(0.2)	$	1.3
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	8.9	$	(0.1)	$	(6.2)	$	2.6
Interest Rate Hedge	Cash Flow		23.2		-		-		23.2
Forward Power Contracts	MTM		9.9		(3.8)		(5.5)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.9		-		(1.1)		0.8
Forward Power Contracts	MTM		2.6		(0.6)		(1.5)		0.5
Total liabilities		$	46.5	$	(4.5)	$	(14.3)	$	27.7

As of March 31, 2013, the table above includes Forward Power Contracts in a short-term asset position of $4.7 million and a long-term asset position of $1.1 million.  This table does not include an asset position of $5.8 million of Forward Power Contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contracts. 

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The following table shows the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2012: 

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward Power Contracts	MTM		2.7		(1.5)		-		1.2
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	Cash Flow		0.5		(0.5)		-		-
Forward Power Contracts	MTM		3.6		(0.6)		-		3.0
Total assets		$	7.5	$	(3.1)	$	(0.2)	$	4.2
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
Interest Rate Hedge	Cash Flow		29.5		-		-		29.5
FTRs	MTM		0.1		-		-		0.1
Forward Power Contracts	MTM		4.1		(1.5)		(2.0)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward Power Contracts	MTM		0.8		(0.6)		(0.1)		0.1
Total liabilities		$	42.7	$	(3.1)	$	(5.1)	$	34.5

As of December 31, 2012, the table above includes Forward power contracts in a short-term asset position of $2.7 million and a long-term asset position of $3.6 million.  This table does not include a short-term asset position of $7.2 million or a long-term asset position of $1.0 million of Forward power contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contracts.

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.   

The aggregate fair value of DPL’s commodity derivative instruments that are in a MTM loss position at March 31, 2013 is $23.3 million.  This amount is offset by $14.3million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts.  This liability position is further offset by the asset position of counterparties with master netting agreements of $4.5 million.  If our counterparties were to call for collateral, we could have to post collateral for the remaining $4.5 million.

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10.  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 DPLER’s wholly owned subsidiary, MC Squared, providing financial or performance assurance to third parties.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis,thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.

At March 31, 2013,  DPL  had $18.0 million of guarantees to third parties for future financial or performance assurance under such agreements, including $17.7 million of guarantees on behalf of DPLE and DPLER and $0.3 million of guarantees on behalf of MC Squared.  The guarantee arrangements entered into by DPL with these third parties cover select present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable by DPL upon written notice within a certain time to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.8 million at March 31, 2013.   

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 DPLwould 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. 

Equity Ownership Interest  

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP.  As of March 31, 2013, DP&L could be responsible for the repayment of 4.9%, or $77.9 million, of a $1,588.8 million debt obligation that features maturities from 2018 to 2040.  This would only happen if this electric generation company defaulted on its debt payments.  As of March 31, 2013, we have no knowledge of such a default. 

Commercial Commitments and Contractual Obligations 

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2012.

Contingencies 

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations.  We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies.  However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2013, cannot be reasonably determined. 

Environmental Matters

DPL’s,  DP&L’s 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 environmental losses that are probable of occurring and can be reasonably estimated.  At March 31, 2013, we have reserves of approximately $3.1 million for environmental matters.  We evaluate the potential liability related to probable losses arising from environmental matters quarterly and may revise our estimates.  Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial position or cash flows.

We have several pending environmental matters associated with our electric generating units and stations.  Some of these matters could have material adverse effects on the operation of the units and stations; especially those that do not have SCR and FGD equipment installed to further control certain emissions.  Currently,

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Hutchings and Beckjord are our only coal-fired generating units or stations that do not have this equipment installed.  DP&L owns 100% of the Hutchings Station and a 50% interest in Beckjord Unit 6.

On July 15, 2011, Duke Energy, a co-owner at Beckjord Unit 6, 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 commonly owned Unit 6, in December 2014.  This was followed by a notification by the joint owners of Beckjord 6 to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit.  We do not believe that any additional accruals are needed as a result of this decision. 

DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated June 1, 2013.  In addition, DP&L has notified PJM that the remaining Hutchings units will be deactivated June 1, 2015.  We do not believe that any additional accruals are needed related to the Hutchings Station. 

Environmental Matters Related to Air Quality

Clean Air Act Compliance

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

Cross-State Air Pollution Rule 

The USEPA promulgated CAIR on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing electric generating stations located in 27 eastern states, including Ohio, and the District of Columbia.  CAIR contemplated two implementation phases.  The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively.  A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015.  To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs.  CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA. 

In response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” in these 27 States,  which is now referred to as CSAPR.  Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources in these 27 states, such as power stations.  Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels.  Many states, utilities and other affected parties filed petitions for review, challenging CSAPR before the U.S. Court of Appeals for the District of Columbia.  A large subset of the petitioners also sought a stay of CSAPR. On December 30, 2011, the D.C. Circuit granted a stay of CSAPR and directed the USEPA to continue administering CAIR. On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that the USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance.  As a result of this ruling, the surviving provisions of CAIR will continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes.  Assuming that the USEPA promulgates a replacement interstate transport rule addressing the D.C. Circuit Court’s ruling, we believe companies will have three years from the date of promulgation before they would be required to comply.  At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial position, results of operations or cash flows. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated.  On January 24, 2013, the D.C. Circuit Court denied this petition for rehearing.  Therefore, CAIR currently remains in effect.  On March 19, 2013, the USEPA and several environmental groups filed two petitions for review of the D.C. Circuit Court’s decision with the U.S. Supreme Court.  If CSAPR were to be reinstated in its current form, we would not expect any material capital costs for DP&L’s units or stations, assuming Beckjord Unit 6 and Hutchings Station will not operate on coal in 2015 due to implementation of MATS.  Because we cannot predict the final outcome of any replacement interstate transport rulemaking, we cannot predict its financial impact on DP&L’s operations. 

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired EGUs.  The standards include new requirements for emissions of mercury and a number

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of other heavy metals.  The USEPA Administrator signed the final rule, now called MATS, on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012.  An additional portion of MATS imposing emissions limits on and requiring pollution control technology at new coal and oil-fueled power plants was finalized on March 28, 2013.  Our affected EGUs will have to come into compliance with MATS by April 16, 2015.  DP&L is evaluating the costs that may be incurred to comply with MATS; however, MATS could have a material adverse effect on our operations and result in material compliance costs. 

On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities.  The final rule was published in the Federal Register on March 21, 2011.  This rule affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities.  The regulations contain emissions limitations, operating limitations and other requirements.  In December 2011, the USEPA proposed additional changes to this rule.  On December 21, 2012, the Administrator of the USEPA signed the final rule and it was published in the Federal Register on January 31, 2013.  Compliance costs are currently 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 December 31, 2012, the USEPA redesignated Adams County, where Stuart and Killen are located, to attainment status.  This status may be temporary, as on December 12, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter.  This will begin a process of redesignations during 2014.  We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial position or results of operations.

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 revisions to the ozone standard, if any, on its operations.  The USEPA is required to review the ozone standard in 2013 and is likely to propose a more stringent standard.

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. 

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.  Numerous units owned and operated by us will be affected by BART.  We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions 

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO₂ emissions from motor vehicles, the USEPA made a finding that CO₂ and certain other GHGs are pollutants under the CAA.  Subsequently, under the CAA, the USEPA determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change.  This finding became effective in January 2010.  On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule.  Under the USEPA’s view, this is the final action that renders CO₂ and other GHGs “regulated air pollutants” under the CAA. 

Under the USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011.  The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs.  Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time.  The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis.  Various industry groups and states petitioned the U.S. Supreme Court to review the D.C.

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Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule.  We cannot predict the outcome of this petition.  The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material. 

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

Approximately 97% of the energy we produce is generated by coal.  DP&L’s share of CO₂  emissions at generating units and stations we own and co-own is approximately 14 million tons annually.  Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial position.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.   

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

Litigation Involving Co-Owned Stations

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system.  Although we were not named as a party to these lawsuits, DP&L is a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L.  Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law. 

As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the Stuart Station are subject to certain specified emission targets related to NO_x, 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 position or cash flows in the future.

Notices of Violation Involving Co-Owned Stations

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 Ohio Power (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 stations.

In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart Station (co-owned by DP&L, Duke Energy and Ohio Power) for alleged violations of the CAA.  The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest, including the NOVs noted in the paragraph above.  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.

On March 13, 2008, Duke Energy, the operator of the Zimmer Station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and air permits for the station in areas including SO₂, opacity and increased heat input. A second NOV and FOV with similar allegations werereceived by Duke Energy on November 4, 2010.  Also in 2010, the USEPA issued an NOV to Zimmer for excess emissions.  DP&L is a co-owner of the Zimmer 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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Notices of Violation Involving Wholly Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station.  The NOVs alleged deficiencies relate to stack opacity and particulate emissions.  Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA.  On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6.  DP&L does not believe that the projects described in the November 2009 NOV were modifications subject to NSR.  DP&L is engaged in discussions with the USEPA and Justice Department to resolve each of these matters, but DP&L is unable to determine the timing, costs or method by which these matters may be resolved.  The Ohio EPA is kept apprised of these discussions.

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

Clean Water Act – Regulation of Water Intake

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures.  The rules required an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  A number of parties appealed the rules.  In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available.  The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011.  We submitted comments to the proposed regulations on August 17, 2011.  In July 2012, the USEPA announced that the final rules will be released in June 2013.  We do not yet know the impact these proposed rules, when finalized, will have on our operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, we submitted an application for the renewal of the Stuart Station NPDES permit that was due to expire on June 30, 2007.  In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River.  On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term.  Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options.  The Ohio EPA issued a revised draft permit that was received on November 12, 2008.  In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit.  In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA.  In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation.  In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011.  We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011.  In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA.  This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA.  The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012.  The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system.  DP&L submitted comments to the draft permit.  In November 2012, Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments.  In December 2012, the USEPA formally withdrew their objection to the permit.  On January 7, 2013, Ohio EPA issued a final permit.  On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission.  Depending on the outcome of the appeals process, the effects could be material on DP&L’s operations.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities.  The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities.  On April 19, 2013,  the USEPA announced a proposed new rule regulating discharge of pollutants from various waste streams associated with steam EGUs.  A 60 day comment period will be triggered once the proposal is published in the Federal Register.  At present, DP&L is reviewing the proposed rule and is currently unable to predict the impact this rulemaking will have on its operations.

In August 2012, DP&L submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013.  At present, the outcome of this proceeding is not known. 

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In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station.  The NOV indicated that construction activities caused sediment to flow into downstream creeks.  In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill.  DP&L has installed sedimentation ponds as part of the runoff control measures to address this issue and is working with the various agencies to resolve their concerns including entering into settlement discussions with the USEPA, although they have not issued any formal NOV.  On March 28, 2013, DP&L received a proposed Administrative Order from the USEPA which is currently under review by DP&L management.  This proposed order may affect the landfill’s construction schedule and delay its operational date.  DP&L has accrued an immaterial amount for anticipated penalties related to this issue.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site.  DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010.  On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site.  On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill.  Discovery, including depositions of past and present DP&L employees, was conducted in 2012.  On February 8, 2013, the Court granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by PRP group in their performing a Remediation Investigation and Feasibility Study.  That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending.  DP&L is unable to predict the outcome of the appeal.  Additionally, the Court’s ruling does not address future litigation that may arise with respect to actual remediation costs.  While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site.  In October 2012, DP&L received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on DP&L’s service center property.  After informal discussions with the USEPA, DP&L complied with this sampling request and the sampling was conducted in February 2013.  On February 28, 2013, the plaintiff’s group referenced above entered into an Administrative Settlement Agreement Consent Order (ASACO) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), percholorethylene (PCE), and methane.  On April 16, 2013, the plaintiff’s group filed a new complaint against DP&L and approximately 25 other defendants alleging that they share liability for these costs.  DP&L will oppose the allegations that it bears any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint.

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site.  Information available to DP&L does not demonstrate that it contributed hazardous substances to the site.  While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls

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(PCBs).  While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L.  While the USEPA had indicated that the official release date for a proposed rule would be sometime in April 2013, it will likely be delayed until late 2013 or early 2014.  At present, DP&L is unable to predict the impact this initiative will have on its operations.

Regulation of Ash Ponds

In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and Stuart Stations.  Subsequently, the USEPA collected similar information for the Hutchings Station. 

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

In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds.  In May 2012, we received a draft report on the inspection.  DP&L submitted comments on the draft report in June 2012.  On March 14, 2013,DP&L received the final report on the inspection of the Killen Station ash pond inspection from the USEPA which included recommended actions.  DP&L is reviewing the final report and will submit a response to the USEPA.  There were no material compliance requirements included in the report.

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.  Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed.  At present, the timing for a final rule regulating coal combustion byproducts cannot be determined, but the USEPA has stated possibly by 2014.  If coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on its operations.

Notice of Violation Involving Co-Owned Units

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

Legal and Other Matters

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

11.  Business Segments

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

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers.  Electricity for

45

the segment’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers who are located in a 6,000 square mile area of West Central Ohio.  DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market.  DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier.  The Competitive Retail segment sells electricity to approximately 247,000 customers located throughout Ohio and in Illinois.  This number includes 137,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier, which was acquired by DPLER in February 2011.  Due to increased competition in Ohio, since 2010 we have increased the number of employees and resources assigned to manage the Competitive Retail segment and increased its marketing to customers.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM.  The majority of intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract.  The Competitive Retail segment has no transmission or generation assets.  The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

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

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

The following tables present financial information for each of DPL’s reportable business segments:

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended March 31, 2013
Revenues from external customers	$	271.8	$	117.3	$	5.5	$	-	$	394.6
Intersegment revenues		104.7		-		0.9		(105.6)		-
Total revenues		376.5		117.3		6.4		(105.6)		394.6
Fuel		88.1		-		0.5		-		88.6
Purchased power		94.1		105.7		0.2		(104.7)		95.3
Amortization of intangibles		-		-		1.8		-		1.8
Gross margin	$	194.3	$	11.6	$	3.9	$	(0.9)	$	208.9
Depreciation and amortization	$	33.6	$	0.1	$	(1.9)	$	-	$	31.8
Interest expense		9.3		0.2		21.2		(0.2)		30.5
Income tax expense (benefit)		9.6		0.9		(4.5)		-		6.0
Net income / (loss)		30.2		1.6		(11.9)		-		19.9
Cash capital expenditures		33.6		-		0.2		-		33.8
At March 31, 2013
Total assets	$	3,439.6	$	95.8	$	738.9	$	-	$	4,274.3

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$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended March 31, 2012
Revenues from external customers	$	312.8	$	112.1	$	9.1	$	-	$	434.0
Intersegment revenues		86.8		-		0.9		(87.7)		-
Total revenues		399.6		112.1		10.0		(87.7)		434.0
Fuel		95.6		-		1.8		-		97.4
Purchased power		84.9		96.7		-		(86.8)		94.8
Amortization of intangibles		-		-		27.8		-		27.8
Gross margin	$	219.1	$	15.4	$	(19.6)	$	(0.9)	$	214.0
Depreciation and amortization	$	34.7	$	0.2	$	(3.5)	$	-	$	31.4
Interest expense		9.6		0.2		20.0		(0.2)		29.6
Income tax expense (benefit)		17.3		3.4		(13.0)		-		7.7
Net income / (loss)		38.1		6.0		(22.4)		-		21.7
Cash capital expenditures		53.2		0.4		0.4		-		54.0
At December 31, 2012
Total assets	$	3,464.2	$	99.2	$	683.9	$	-	$	4,247.3

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FINANCIAL STATEMENTS

The Dayton Power and Light Company

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF RESULTS OF OPERATIONS
	Three months ended March 31,
$ in millions	2013		2012
Revenues	$	376.5	$	399.6
Cost of revenues:
Fuel		88.1		95.6
Purchased power		94.1		84.9
Total cost of revenues		182.2		180.5
Gross margin		194.3		219.1
Operating expenses:
Operation and maintenance		91.3		99.2
Depreciation and amortization		33.6		34.7
General taxes		19.8		20.2
Total operating expenses		144.7		154.1
Operating income		49.6		65.0
Other income / (expense), net:
Investment income		0.1		0.1
Interest expense		(9.3)		(9.6)
Other expense		(0.6)		(0.1)
Total other income / (expense), net		(9.8)		(9.6)
Earnings before income taxes		39.8		55.4
Income tax expense		9.6		17.3
Net income		30.2		38.1
Dividends on preferred stock		0.2		0.2
Earnings on common stock	$	30.0	$	37.9
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three months ended March 31,
$ in millions	2013		2012
Net income	$	30.2	$	38.1
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax expense of $(0.2) and $(0.2) for each respective period		0.2		0.4
Reclassification to earnings, net of income tax expense of $0.0 and $0.0 for each respective period		0.1		-
Total change in fair value of available-for-sale securities		0.3		0.4
Derivative activity:
Change in derivative fair value, net of income tax benefit of $1.4 and $0.8 for each respective period		(2.6)		(1.5)
Reclassification to earnings, net of income tax benefit of $0.2 and $0.6 for each respective period		(0.2)		(1.7)
Total change in fair value of derivatives		(2.8)		(3.2)
Pension and postretirement activity:
Prior service cost for the period net of income tax expense of $(0.5) and $0.0, for each respective period		0.9		-
Reclassification to earnings, net of income tax expense of $0.0 and $(0.7) for each respective period		-		1.1
Total change in unfunded pension obligation		0.9		1.1
Other comprehensive loss		(1.6)		(1.7)
Net comprehensive income	$	28.6	$	36.4
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
	Three months ended March 31,
$ in millions	2013		2012
Cash flows from operating activities:
Net income	$	30.2	$	38.1
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization		33.6		34.7
Deferred income taxes		22.9		(2.4)
Changes in certain assets and liabilities:
Accounts receivable		13.2		(0.6)
Inventories		(4.3)		(2.0)
Taxes applicable to subsequent years		16.7		21.5
Deferred regulatory costs, net		3.6		7.1
Accounts payable		2.7		(2.2)
Accrued taxes payable		(25.3)		(15.0)
Accrued interest payable		2.3		7.5
Pension, retiree, and other benefits		3.2		2.1
Unamortized investment tax credit		(0.6)		(0.6)
Other		3.6		10.8
Net cash from operating activities		101.8		99.0
Cash flows from investing activities:
Capital expenditures		(33.6)		(53.2)
Purchase of renewable energy credits		(0.5)		(0.7)
Increase in restricted cash		(12.7)		(8.7)
Net cash used for investing activities		(46.8)		(62.6)

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (cont.)
	Three months ended March 31,
$ in millions	2013		2012
Net cash from financing activities:
Dividends paid on common stock to parent		(55.0)		(45.0)
Dividends paid on preferred stock		(0.2)		(0.2)
Net cash from financing activities		(55.2)		(45.2)
Cash and cash equivalents:
Net change		(0.2)		(8.8)
Balance at beginning of period		28.5		32.2
Cash and cash equivalents at end of period	$	28.3	$	23.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	7.9	$	2.4
Income taxes paid, net	$	(20.0)	$	6.1
Non-cash financing and investing activities:
Accruals for capital expenditures	$	10.6	$	24.1
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
	At		At
	March 31,		December 31,
$ in millions	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	28.3	$	28.5
Restricted cash		23.4		10.7
Accounts receivable, net (Note 2)		148.2		160.0
Inventories (Note 2)		113.2		108.9
Taxes applicable to subsequent years		50.0		66.7
Regulatory assets, current (Note 3)		16.6		18.3
Other prepayments and current assets		34.9		33.0
Total current assets		414.6		426.1
Property, plant & equipment:
Property, plant & equipment		5,270.6		5,249.0
Less: Accumulated depreciation and amortization		(2,525.2)		(2,516.3)
		2,745.4		2,732.7
Construction work in process		70.4		87.8
Total net property, plant & equipment		2,815.8		2,820.5
Other noncurrent assets:
Regulatory assets, non-current (Note 3)		180.9		185.5
Intangible assets, net of amortization		9.4		9.0
Other deferred assets		18.9		23.1
Total other noncurrent assets		209.2		217.6
Total assets	$	3,439.6	$	3,464.2
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
	At		At
	March 31,		December 31,
$ in millions	2013		2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion - long-term debt (Note 5)	$	570.4	$	570.4
Accounts payable		76.7		79.1
Accrued taxes		66.9		92.2
Accrued interest		15.4		13.1
Customer security deposits		33.9		35.2
Regulatory liabilities, current (Note 3)		-		0.1
Other current liabilities		56.0		52.1
Total current liabilities		819.3		842.2
Noncurrent liabilities:
Long-term debt (Note 5)		332.7		332.7
Deferred taxes (Note 6)		673.3		652.0
Taxes payable		66.0		66.0
Regulatory liabilities, non-current (Note 3)		118.8		117.3
Pension, retiree and other benefits		63.2		61.6
Unamortized investment tax credit		26.8		27.4
Other deferred credits		44.0		43.0
Total noncurrent liabilities		1,324.8		1,300.0
Redeemable preferred stock		22.9		22.9
Commitments and contingencies (Note 11)
Common shareholder's equity:
Common stock, at par value of $0.01 per share:		0.4		0.4
Other paid-in capital		803.3		803.2
Accumulated other comprehensive loss		(40.3)		(38.7)
Retained earnings		509.2		534.2
Total common shareholder's equity		1,272.6		1,299.1
Total liabilities and shareholder's equity	$	3,439.6	$	3,464.2
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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The Dayton Power and Light Company

Notes to Condensed Financial Statements (Unaudited)

1.  Overview and Summary of Significant Accounting Policies 

Description of Business  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.  DP&L is a wholly owned subsidiary of DPL. 

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

DP&L’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. 

DP&L employed 1,412 people as of March 31, 2013.  Approximately 55% of all employees are under a collective bargaining agreement which expires on October 31, 2014. 

Financial Statement Presentation  

DP&L does not have any subsidiaries.  DP&L has undivided ownership interests in seven electric generating facilities and numerous transmission facilities which are included in the financial statements at amortized cost.  Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statement of Operations.  See Note 4 for more information.   

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X.  Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report.  Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.   

In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2013; our results of operations for the three months ended March 31, 2013 and 2012 and our cash flows for the three months ended March 31, 2013 and 2012.  Unless otherwise noted, all adjustments are normal and recurring in nature.  Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013. 

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

55

regulated construction projects.  For non-regulated property including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. 

Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.  The total of AFUDC and capitalized interest was $0.3 million and $1.4 million for the three months ended March 31, 2013 and 2012, respectively. 

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

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

Intangibles 

Intangibles consist of emission allowances and renewable energy credits.  Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances.  Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.  Emission allowances are amortized as they are used in our operations.  Renewable energy credits are amortized as they are used or retired.  During the three months ended March 31, 2013 and 2012, DP&L had no gains from the sale of emission allowances.

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.  These taxes are accounted for on a net basis and are recorded as a reduction in revenues.  The amounts for the three months ended March 31, 2013 and 2012 were $13.4 million and $12.9 million, respectively.

Related Party Transactions 

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

	Three months ended
	March 31,
	2013		2012
DP&L Revenues:
Sales to DPLER (a)	$	78.7	$	83.0
Sales to MC Squared	$	25.6	$	-
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.6)
Expense recoveries for services provided to DPLER (c)	$	1.1	$	0.9
DP&L Customer security deposits:
Deposits received from DPLER (d)	$	19.2	$	-

(a)DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers.  The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The decrease in DP&L’s sales to DPLER during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, is primarily due to the transfer price for the current customer base being lower than the previous year’s transfer price.  The increase in DP&L’s sales to MC Squared during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, is a result of these sales beginning in September 2012. 

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

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

(d)DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity.  Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.

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Recently Issued Accounting Standards 

Offsetting Assets and Liabilities

The FASB recently issued ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”to limit the scope of ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” to derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions.  This ASU became effective for annual and interim periods beginning on or after January 1, 2013.  The FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220):  Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards  

Offsetting Assets and Liabilities 

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

Testing Indefinite-Lived Intangible Assets for Impairments 

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012.  We adopted this ASU on January 1, 2013.  This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.”  ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30.  These new rules did not have a material impact on our overall results of operations, financial position or cash flows. 

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2.  Supplemental Financial Information 

Accounts receivable and Inventories are as follows at March 31, 2013 and December 31, 2012:

	At		At
	March 31,		December 31,
$ in millions	2013		2012
Accounts receivable, net:
Unbilled revenue	$	41.6	$	48.1
Customer receivables		68.3		62.0
Amounts due from partners in jointly owned plants		15.3		19.7
Coal sales		-		1.6
Other		24.0		29.5
Provision for uncollectible accounts		(1.0)		(0.9)
Total accounts receivable, net	$	148.2	$	160.0
Inventories, at average cost:
Fuel and limestone	$	71.9	$	67.3
Plant materials and supplies		39.4		39.8
Other		1.9		1.8
Total inventories, at average cost	$	113.2	$	108.9

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months ended March 31, 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statement of Operations	Three months ended March 31,
$ in millions		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.2
	Total before income taxes		0.2
	Tax expense		(0.1)
	Net of income taxes		0.1
Gains and losses on cash flow hedges: (Note 9)
	Interest expense		(0.6)
	Revenue		(0.5)
	Purchased power		1.1
	Total before income taxes		-
	Tax expense		(0.2)
	Net of income taxes		(0.2)
Total reclassifications for the period, net of income taxes		$	(0.1)

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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months ended March 31, 2013 are as follows:

$ in millions	Gains / (losses) on Available-for-sale securities		Gains / (losses) on Cash Flow Hedges		Change in Unfunded Pension Obligation		Total
Balance January 1, 2013	$	1.0	$	2.6	$	(42.3)	$	(38.7)
Other comprehensive income / (loss) before reclassifications		0.2		(2.6)		0.9		(1.5)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1		(0.2)		-		(0.1)
Net current period other comprehensive income / (loss)		0.3		(2.8)		0.9		(1.6)
Balance March 31, 2013	$	1.3	$	(0.2)	$	(41.4)	$	(40.3)

3.  Regulatory Assets and Liabilities 

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

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

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

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

$ in millions	Type of Recovery (a)	Amortization through	At March 31, 2013		At December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	6.6	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		10.0		11.3
Total regulatory assets, current			$	16.6	$	18.3
Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	34.3	$	35.1
Pension benefits	C	Ongoing		87.3		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.7		11.9
Regional transmission organization costs	D	2014		2.2		2.6
Deferred storm costs	D			24.7		24.4
CCEM smart grid and advanced metering infrastructure costs	D			6.6		6.6
CCEM energy efficiency program costs	F	Ongoing		3.4		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.6		4.7
Total regulatory assets, non-current			$	180.9	$	185.5
Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.6	$	112.1
Postretirement benefits				4.8		5.0
Other				0.4		0.2
Total regulatory liabilities, non-current			$	118.8	$	117.3

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

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

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

F – Recovery of incurred costs plus rate of return. 

Regulatory Assets 

TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM.  On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.   

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider.  The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter.  DP&L implemented the fuel and purchased power recovery rider on January 1, 2010.  As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process.  

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as the result of amounts previously provided to customers.  This is the cumulative flow

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through benefit given to regulated customers that will be collected from them in future years.  Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time. 

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

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

Regional transmission organization costs represent costs incurred to join an RTO.  The recovery of these costs will be requested in a future FERC rate case.   

Deferred storm costs relate to costs incurred to repair the damage caused by storms in the following years:

· 2008 – related to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other 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.

· 2011 – related to five major storms in 2011.  On December 21, 2012, DP&L filed a request with the PUCO for an accounting order to defer costs and a request for recovery of costs associated with these storms.  At March 31, 2013, DP&L believes the recovery of these costs is probable.

· 2012 – related to storm damage that occurred during the final weekend of June 2012.  On August 10, 2012, DP&L filed a request with the PUCO, which was modified on October 19, 2012, for an accounting order to defer the costs associated with this storm damage.  On December 19, 2012, the PUCO issued an order permitting partial deferral. 

On December 21, 2012, DP&L filed a request for recovery of all of these deferred storm costs with the PUCO.

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.  On April 29, 2011, DP&L filed to true-up the energy efficiency rider which was approved by the PUCO on October 18, 2011.  DP&Lmade its true-up filing on April 30, 2013. 

Consumer education campaign represents costs for consumer education advertising regarding electric deregulation.  DP&L will be seeking recovery of these costs as part of our next distribution rate case filing at the PUCO.  The timing of such a filing has not yet been determined. 

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

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

Regulatory Liabilities 

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

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

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities with certain other Ohio utilities.  Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on the energy taken.  The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  As of March 31, 2013, DP&L had $31.0 million of construction work in process at such jointly owned facilities.  DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.  Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned unit or station. 

DP&L’s undivided ownership interest in such facilities as well as our wholly owned coal-fired Hutchings Station at March 31, 2013, is as follows: 

	DP&L Share			DP&L Investment
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)	Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Beckjord Unit 6	50.0	207	$	76	$	64	$	-	No
Conesville Unit 4	16.5	129		28		2		4	Yes
East Bend Station	31.0	186		209		137		3	Yes
Killen Station	67.0	402		617		302		9	Yes
Miami Fort Units 7 and 8	36.0	368		361		148		3	Yes
Stuart Station	35.0	808		744		297		10	Yes
Zimmer Station	28.1	365		1,097		644		2	Yes
Transmission (at varying percentages)				97		59		-
Total		2,465	$	3,229	$	1,653	$	31
Wholly owned production station:
Hutchings Station	100.0	365	$	-	$	-	$	-	No

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

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DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated on June 1, 2013.  In addition, DP&L has notified PJM that the remaining coal-fired units at Hutchings Station will be deactivated on June 1, 2015.  The decision to deactivate these remaining coal-fired units has been made because these units are not equipped with the advanced environmental control technologies needed to comply with the MATS, and the expected cost of compliance with MATS for these units would exceed the expected return.  Additionally, conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return.

As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a zero fair market value.  Since DP&L did not apply push down accounting, this valuation did not affect the book value of these stations’ or units’ valuation at DP&L.

5.  Debt Obligations 

Long-term debt

$ in millions	March 31, 2013		December 31, 2012
Pollution control series maturing in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series maturing in January 2034 - 4.8%		179.1		179.1
Pollution control series maturing in September 2036 - 4.8%		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligation		0.1		0.1
Unamortized debt discount		(0.1)		(0.1)
Total non-current portion - long-term debt - DP&L	$	332.7	$	332.7

Current portion of long-term debt

$ in millions	March 31, 2013		December 31, 2012
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0	$	470.0
Pollution control series maturing in November 2040 - variable rates: 0.10% - 0.16% and 0.04% - 0.26% (a)		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.3		0.3
Total current portion - long-term debt - DP&L	$	570.4	$	570.4

(a) Range of interest rates for the three months ended March 31, 2013 and the twelve months ended December 31, 2012, respectively. 

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At March 31, 2013, maturities of long-term debt, including capital lease obligations, are as follows:

$ in millions
Due within one year	$	570.4
Due within two years		0.2
Due within three years		0.1
Due within four years		0.1
Due within five years		0.1
Thereafter		332.3
Total maturities		903.2
Unamortized discounts		(0.1)
Total long-term debt	$	903.1

On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040.  In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds.  The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A.  This standby letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses.  If the standby letter of credit expires, this would trigger a mandatory tender of all of the outstanding bonds, therefore, we have reflected these outstanding bonds as a current liability.  Fees associated with this standby letter of credit facility were not material during the three months ended March 31, 2013 and 2012.   

On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  The agreement provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.This agreement, originally for a three year term expiring on April 20, 2013, was extended through May 31, 2013 by an amendment dated April 11, 2013 that was negotiated between DP&L and the syndicated bank group. DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013, DP&L had no outstanding letters of credit against this facility.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013, DP&L had no outstanding letters of credit against this facility. 

Prior to the expiration of the DP&L amended revolving credit facility (that is now scheduled to expire on May 31, 2013) and in no case later than the end of the second quarter of 2013, DP&L intends to enter into a new $275.0 million to $350.0 million revolving credit facility and to extinguish both of the existing DP&L revolving credit facilities discussed above. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing.  The terms and conditions of this new revolving credit facility have not been finalized, but it is expected that they will be substantially similar to those of the existing DP&L revolving credit facilities.  As of the date of filing of this quarterly report on Form 10-Q, DP&L has the bank commitments required to close the new DP&L revolving credit facility.

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

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 filed for approval to refinance the $470.0 million of first mortgage bonds maturing in October 2013 with the PUCO on April 12, 2013.  Subsequent to the receipt of this approval and no later than the end of the third quarter of 2013, DP&L intends to access the debt capital markets to refinance these bonds.

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6.  Income Taxes 

The following table details the effective tax rates for the three months endedMarch 31, 2013 and 2012. 

	Three months ended March 31,
	2013	2012
DP&L	24.1%	31.3%

Income tax expense for the three months endedMarch 31, 2013 and 2012 was calculated using the estimated annual effective income tax rates for 2013 and 2012 of 28.8%  and 31.1%, respectively.  Management estimates the annual effective tax rate based upon its forecast of annual pre-tax income.  To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

For the three months ended March 31, 2013, DP&L’s current period effective rate is less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 IRS examination in the first quarter of 2013.  The decrease in the effective rate compared to the same period in 2012 is also primarily due to the resolution of the 2008 IRS examination. 

Deferred tax liabilities for DP&L increased by approximately $21.3 million during the three months endedMarch 31, 2013primarily related to the resolution of the 2008 IRS examination.  

The Internal Revenue Service began an examination of our 2008 federal income tax return during the second quarter of 2010.  The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013.  As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense.

7.  Pension and Postretirement Benefits 

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

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three months ended March 31, 2013 or 2012.

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

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The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months endedMarch 31, 2013 and 2012 was: 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended March 31,		Three months ended March 31,		Three months ended March 31,		Three months ended March 31,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	0.1	$	0.1
Interest cost		3.9		4.3		0.2		0.3
Expected return on assets (a)		(5.9)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		2.3		2.7		(0.1)		(0.2)
Prior service cost		0.7		0.8		-		-
Net periodic benefit cost / (income)	$	2.8	$	3.6	$	0.1	$	0.1

(a)   For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used.  GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $335.0 million, respectively. 

Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated Future Benefit Payments and Medicare Part D Reimbursements
$ in millions	Pension		Postretirement
2013	$	16.6	$	1.7
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		124.4		6.8

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 method is available to us.  The value of our financial instruments represents our best estimates of fair value, which may not be the value realized in the future.  The following table presents the fair value and cost of our non-derivative instruments at March 31, 2013 and December 31, 2012.  See also Note 9 for the fair values of our derivative instruments. 

	At March 31,				At December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities		4.0		5.7		4.0		5.1
Debt Securities		4.5		4.9		4.6		5.0
Multi-Strategy Fund		0.3		0.3		0.3		0.3
Total Assets	$	9.0	$	11.1	$	9.1	$	10.6
Liabilities
Debt	$	903.1	$	921.8	$	903.1	$	926.9

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These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Consolidated Balance Sheet at their gross fair value, except for Debt which is presented at amortized cost.

Debt 

The fair value of debt is based on current public market prices for disclosure purposes only.  Unrealized gains or losses are not recognized in the financial statements because debt is presented at amortized cost in the financial statements.  The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2013 to 2061. 

Master Trust Assets 

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes.  These assets are primarily comprised of open-ended mutual funds which are valued using the net asset value per unit.  These investments are recorded at fair value within Other assets on the balance sheets and classified as available for sale.  Any unrealized gains or losses are recorded in AOCI until the securities are sold.   

DP&L had $2.1 million ($1.4 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2013 and $1.6 million ($1.0 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2012.   

$0.1 million ($0.1 million after tax) of various investments were sold during the quarter to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  

Net Asset Value (NAV) per Unit 

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of March 31, 2013.  These assets are part of the Master Trust.  Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date.  Investments that have restrictions on the redemption of the investments are Level 3 inputs.  At March 31, 2013, DP&L did not have any investments for sale at a price different from the NAV per unit. 

Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at March 31, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	-	Immediate
Equity Securities (b)		5.7		5.1		-	Immediate
Debt Securities (c)		4.9		5.0		-	Immediate
Multi-Strategy Fund (d)		0.3		0.3		-	Immediate
Total	$	11.1	$	10.6	$	-

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

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

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

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

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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.  

The fair value of assets and liabilities at March 31, 2013 and December 31, 2012 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows: 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.7		-		5.7		-
Debt Securities		4.9		-		4.9		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		11.1		0.2		10.9		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.6		-		6.6		-
Total Derivative Assets		6.8		0.2		6.6		-
Total Assets	$	17.9	$	0.4	$	17.5	$	-
Liabilities
Derivative Liabilities
Forward Power Contracts	$	22.9	$	-	$	22.9	$	-
Total Derivative Liabilities		22.9		-		22.9		-
Long-term Debt		921.8		-		903.0		18.8
Total Liabilities	$	944.7	$	-	$	925.9	$	18.8

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Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		7.3		-		7.3		-
Total Derivative Assets		7.5		0.2		7.3		-
Total Assets	$	18.1	$	0.4	$	17.7	$	-
Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Forward Power Contracts		11.6		-		11.6		-
Total Derivative Liabilities		11.7		-		11.6		0.1
Long-term debt		926.9		-		908.0		18.9
Total Liabilities	$	938.6	$	-	$	919.6	$	19.0

We use the market approach to value our financial instruments.  Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents.  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 forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market).  Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit; and interest rate hedges, which use observable inputs to populate a pricing model.  Financial transmission rights are considered a Level 3 input because the monthly auctions are considered inactive. 

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

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

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

Non-recurring Fair Value Measurements 

We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other

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management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  Additions to AROs were not material during the three months ended March 31, 2013 and 2012. 

9.  Derivative Instruments and Hedging Activities 

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

At March 31, 2013, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		2.8		-		2.8
Heating Oil Futures		Mark to Market	Gallons		1,890.0		-		1,890.0
Forward Power Contracts		Cash Flow Hedge	MWh		842.6		(2,040.9)		(1,198.3)
Forward Power Contracts		Mark to Market	MWh		2,221.4		(7,069.8)		(4,848.4)

At December 31, 2012, DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating Oil Futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward Power Contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward Power Contracts		Mark to Market	MWh		2,296.6		(4,760.4)		(2,463.8)

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 is determined by observable market prices available as of the balance sheet dates and will continue to fluctuate with changes in market prices up to contract expiration.  The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring.  The ineffective portion of the cash flow hedge is recognized in earnings in the current period.  All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. 

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. 

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The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2013 and 2012: 

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(4.7)	$	7.3	$	(0.8)	$	9.8
Net gains / (losses) associated with current period hedging transactions		(2.6)		-		(1.5)		-
Net gains reclassified to earnings
Interest Expense		-		(0.6)		-		(0.6)
Revenues		(0.3)		-		(1.2)		-
Purchased Power		0.7		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	(6.9)	$	6.7	$	(3.4)	$	9.2
Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest Expense	$	-	$	-
Revenues	$	-	$	-
Purchased Power	$	-	$	-
Portion expected to be reclassified to earnings in the next twelve months (a)	$	8.8	$	-
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21		5

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

Mark to Market Accounting 

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

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 and are recognized in the 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 gain that is probable of being returned to customers should be deferred as a regulatory liability.  Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010.  Therefore, the Ohio retail

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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 statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three months ended March 31, 2013 and 2012: 

For the three months ended March 31, 2013
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	-	$	-	$	-	$	(10.4)	$	(10.4)
Realized gain / (loss)		-		-		0.5		0.7		1.2
Total	$	-	$	-	$	0.5	$	(9.7)	$	(9.2)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	-	$	-	$	-	$	-	$	-
Regulatory (asset) / liability		-		-		-		-		-
Recorded in Income Statement: gain / (loss)
Revenue		-		-		-		(1.1)		(1.1)
Purchased Power		-		-		0.5		(8.6)		(8.1)
Fuel		-		-		-		-		-
O&M		-		-		-		-		-
Total	$	-	$	-	$	0.5	$	(9.7)	$	(9.2)

For the three months ended March 31, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(7.8)	$	(0.1)	$	(0.1)	$	-	$	(8.0)
Realized gain / (loss)		(5.0)		0.9		(0.2)		-		(4.3)
Total	$	(12.8)	$	0.8	$	(0.3)	$	-	$	(12.3)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	(3.5)	$	-	$	-	$	-	$	(3.5)
Regulatory (asset) / liability		(1.1)		0.1		-		-		(1.0)
Recorded in Income Statement: gain / (loss)
Revenue		-		-		-		1.6		1.6
Purchased Power		-		-		(0.3)		(1.6)		(1.9)
Fuel		(8.2)		0.6		-		-		(7.6)
O&M		-		0.1		-		-		0.1
Total	$	(12.8)	$	0.8	$	(0.3)	$	-	$	(12.3)

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DP&L has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.  The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.  The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments at March 31, 2013:

Fair Values of Derivative Instruments
at March 31, 2013
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.2	$	(0.1)	$	-	$	0.1
Forward Power Contracts	MTM		5.3		(3.8)		-		1.5
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	MTM		1.1		(0.6)		-		0.5
Total assets		$	6.8	$	(4.5)	$	(0.2)	$	2.1
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	8.9	$	(0.1)	$	(6.2)	$	2.6
Forward Power Contracts	MTM		9.5		(3.8)		(5.1)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.9		-		(1.1)		0.8
Forward Power Contracts	MTM		2.6		(0.6)		(1.5)		0.5
Total liabilities		$	22.9	$	(4.5)	$	(13.9)	$	4.5

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The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2012:

Fair Values of Derivative Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward Power Contracts	MTM		2.8		(1.5)		-		1.3
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	Cash Flow		0.5		(0.5)		-		-
Forward Power Contracts	MTM		3.6		(0.6)		-		3.0
Total assets		$	7.6	$	(3.1)	$	(0.2)	$	4.3
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
FTRs	MTM		0.1		-		-		0.1
Forward Power Contracts	MTM		2.7		(1.5)		(0.5)		0.7
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward Power Contracts	MTM		0.7		(0.6)		-		0.1
Total liabilities		$	11.7	$	(3.1)	$	(3.5)	$	5.1

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.   

The aggregate fair value of DP&L’s commodity derivative instruments that are in a MTM loss position at March 31, 2013 is $22.9 million.  This amount is offset by $13.9 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts.  This liability position is further offset by the asset position of counterparties with master netting agreements of $4.5 million.  If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $4.5 million.

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10.  Shareholder’s Equity

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at March 31, 2013.  All common shares are held by DP&L’s parent, DPL.

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

11.  Contractual Obligations, Commercial Commitments and Contingencies

DP&L – Equity Ownership Interest  

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP.  As of March 31, 2013, DP&L could be responsible for the repayment of 4.9%, or $77.9 million, of a $1,588.8 million debt obligation that features maturities from 2018 to 2040.  This would only happen if this electric generation company defaulted on its debt payments.  As of March 31, 2013, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2012.

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our Condensed Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies.  However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Financial Statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2013, cannot be reasonably determined.

Environmental Matters

DP&L’s 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 environmental losses that are probable of occurring and can be reasonably estimated.  At March 31, 2013, we have reserves of approximately $3.1 million for environmental matters.  We evaluate the potential liability related to probable losses arising from environmental matters quarterly and may revise our estimates.  Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial position or cash flows.

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

On July 15, 2011, Duke Energy, a co-owner at Beckjord Unit 6, 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 commonly owned Unit 6, in December 2014.  This was followed by a notification by the joint owners of Beckjord Unit 6 to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit.  We are depreciating Beckjord Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision. 

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DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated June 1, 2013.  In addition, DP&L has notified PJM that the remaining Hutchings units will be deactivated June 1, 2015.  We do not believe that any additional accruals are needed related to the Hutchings Station. 

Environmental Matters Related to Air Quality

Clean Air Act Compliance

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

Cross-State Air Pollution Rule 

The USEPA promulgated the Clean Air Interstate Rule (CAIR) on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing electric generating stations located in 27 eastern states, including Ohio, and the District of Columbia.  CAIR contemplated two implementation phases.  The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively.  A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015.  To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs.  CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA.

In response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” in these 27 States,  which is now referred to as the Cross-State Air Pollution Rule (CSAPR).  Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources in these 27 states, such as power stations.  Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of73% and additional NO_x reductions of 54%  from 2005 levels.  Many states, utilities and other affected parties filed petitions for review, challenging CSAPR before the U.S. Court of Appeals for the District of Columbia.  A large subset of the petitioners also sought a stay of CSAPR. On December 30, 2011, the D.C. Circuit granted a stay of CSAPR and directed the USEPA to continue administering CAIR. On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance.  As a result of this ruling, the surviving provisions of CAIR will continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes.  Assuming that the USEPApromulgates a replacement interstate transport rule addressing the D.C. Circuit Court’s ruling, we believe companies will have three years from the date of promulgation before they would be required to comply.  At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial position, results of operations or cash flows. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated.  On January 24, 2013, the D.C. Circuit Court denied this petition for rehearing.  Therefore, CAIR currently remains in effect.  On March 19, 2013, the USEPA and several environmental groups filed two petitions for review of the D.C. Circuit Court’s decision with the U.S. Supreme Court.  If CSAPR were to be reinstated in its current form, we would not expect any material capital costs for DP&L’s units or stations, assuming Beckjord Unit 6 and Hutchings Station will not operate on coal in 2015 due to implementation of the MATS.  Because we cannot predict the final outcome of any replacement interstate transport rulemaking, we cannot predict its financial impact on DP&L’s operations. 

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired EGUs.  The standards include new requirements for emissions of mercury and a number of other heavy metals.  The USEPA Administrator signed the final rule, now called MATS, on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012.  An additional portion of MATS imposing emissions limits on and requiring pollution control technology at new coal and oil-fueled power plants was finalized on March 28, 2013.  Our affected EGUs will have to come into compliance with MATS by April 16, 2015.  DP&L is evaluating the costs that may be incurred to comply with MATS; however, MATS could have a material adverse effect on our operations and result in material compliance costs. 

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On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities.  The final rule was published in the Federal Register on March 21, 2011.  This rule affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities.  The regulations contain emissions limitations, operating limitations and other requirements.  In December 2011, the USEPA proposed additional changes to this rule.  On December 21, 2012, the Administrator of the USEPA signed the final rule and it was published in the Federal Register on January 31, 2013.  Compliance costs are currently 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 December 31, 2012, the USEPA redesignated Adams County, where Stuart and Killen are located, to attainment status.  This status may be temporary, as on December 12, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter.  This will begin a process of redesignations during 2014.  We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial position or results of operations.

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 revisions to the ozone standard, if any, on its operations.The USEPA is required to review the ozone standard in 2013 and is likely to propose a more stringent standard.

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. 

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.  Numerous units owned and operated by us will be affected by BART.  We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions 

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO₂ emissions from motor vehicles, the USEPA made a finding that CO₂ and certain other GHGs are pollutants under the CAA.  Subsequently, under the CAA, the USEPA determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change.  This finding became effective in January 2010.  On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule.  Under the USEPA’s view, this is the final action that renders CO₂ and other GHGs “regulated air pollutants” under the CAA. 

Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011.  The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs.  Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time.  The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis.  Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule.  We cannot predict the outcome of this petition.  The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material. 

On April 13, 2012, the USEPA published its proposed GHG standards for new EGUsunder CAA subsection 111(b), which would require certain new EGUs to meet a standard of1,000 pounds of CO₂ per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation.  The

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proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive CO₂ emission control technology to meet the standard.  Furthermore, the USEPA may propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d).  These latter rules may focus on energy efficiency improvements at electric generating stations.  We cannot predict the effect of these standards, if any, on DP&L’s operations.

Approximately 97% 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 14 million tons annually.  Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial position.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.   

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

Litigation Involving Co-Owned Units

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system.  Although we were not named as a party to these lawsuits, DP&L is a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L.  Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law. 

As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the Stuart Station are subject to certain specified emission targets related to NO_x, 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 position or cash flows in the future.

Notices of Violation Involving Co-Owned Units

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 Ohio Power (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 units.

In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart Station (co-owned by DP&L, Duke Energy and Ohio Power) for alleged violations of the CAA.  The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest, including the NOVs noted in the paragraph above.  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.

On March 13, 2008, Duke Energy, the operator of the Zimmer Station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and air permits for the station in areas including SO₂, opacity and increased heat input. A second NOV and FOV with similar allegations was received by Duke Energy on November 4, 2010.  Also in 2010, the USEPA issued an NOV to Zimmer for excess emissions.  DP&L is a co-owner of the Zimmer Station and could be affected by the eventual resolution of these matters.  Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters.  DP&L is unable to predict the outcome of these matters.

Notices of Violation Involving Wholly Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station.  The NOVs alleged deficiencies relate to stack opacity and particulate emissions.  Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA.  On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6.  DP&L does not believe that the projects described in the November 2009 NOV were modifications subject to NSR.  DP&L is engaged in discussions with the USEPA and

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Justice Department to resolve each of these matters, but DP&L is unable to determine the timing, costs or method by which these matters may be resolved.  The Ohio EPA is kept apprised of these discussions.

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

Clean Water Act – Regulation of Water Intake

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures.  The rules required an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  A number of parties appealed the rules.  In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available.  The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011.  We submitted comments to the proposed regulations on August 17, 2011.  In July 2012, the USEPA announced that the final rules will be released in June 2013.  We do not yet know the impact these proposed rules, when finalized, will have on our operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, we submitted an application for the renewal of the Stuart Station NPDES permit that was due to expire on June 30, 2007.  In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River.  On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term.  Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options.  The Ohio EPA issued a revised draft permit that was received on November 12, 2008.  In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit.  In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA.  In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation.  In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011.  We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011.  In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA.  This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA.  The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012.  The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system.  DP&L submitted comments to the draft permit.  In November 2012, Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments.  In December 2012, the USEPA formally withdrew their objection to the permit.  On January 7, 2013, Ohio EPA issued a final permit.  On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission.  Depending on the outcome of the appeals process, the effects could be material on DP&L’s operations.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities.  The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities.  On April 19, 2013,  the USEPA announced a proposed new rule regulating discharge of pollutants from various waste streams associated with steam EGUs.  A 60 day comment period will be triggered once the proposal is published in the Federal Register.  At present, DP&L is reviewing the proposed rule and is currently unable to predict the impact this rulemaking will have on its operations.

In August 2012, DP&L submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013.  At present, the outcome of this proceeding is not known. 

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station.  The NOV indicated that construction activities caused sediment to flow into downstream creeks.  In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill.  DP&L has installed sedimentation ponds as part of the runoff control measures to address this issue and is working with the various agencies to resolve their concerns including entering into settlement discussions with the USEPA, although they have not issued any formal NOV.  On March 28, 2013, DP&L received a proposed Administrative Order from

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the USEPA which is currently under review by DP&L management.  This proposed order may affect the landfill’s construction schedule and delay its operational date.  DP&L has accrued an immaterial amount for anticipated penalties related to this issue.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site.  DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010.  On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site.  On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill.  Discovery, including depositions of past and present DP&L employees, was conducted in 2012.  On February 8, 2013, the Court granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by PRP group in their performing a Remediation Investigation and Feasibility Study.  That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending.  DP&L is unable to predict the outcome of the appeal.  Additionally, the Court’s ruling does not address future litigation that may arise with respect to actual remediation costs.  While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations. 

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site.  In October 2012, DP&L received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on DP&L’s service center property.  After informal discussions with the USEPA, DP&L complied with this sampling request and the sampling was conducted in February 2013.  On February 28, 2013, the plaintiff’s group referenced above entered into an Administrative Settlement Agreement Consent Order (ASACO) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), percholorethylene (PCE), and methane.  On April 16, 2013, the plaintiff’s group filed a new complaint against DP&L and approximately 25 other defendants alleging that they share liability for these costs.  DP&L will oppose the allegations that it bears any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint.

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site.  Information available to DP&L does not demonstrate that it contributed hazardous substances to the site.  While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs).  While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L.  While the USEPA had indicated that the official release date for a proposed rule would be sometime in April 2013, it will likely be delayed until late 2013 or early 2014.  At present, DP&L is unable to predict the impact this initiative will have on its operations.

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Regulation of Ash Ponds

In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and Stuart Stations.  Subsequently, the USEPA collected similar information for the Hutchings Station. 

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

In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds.  In May 2012, we received a draft report on the inspection.  DP&L submitted comments on the draft report in June 2012.  On March 14, 2013,DP&L received the final report on the inspection of the Killen Station ash pond inspection from the USEPA which included recommended actions.  DP&L is reviewing the final report and will submit a response to the USEPA.  There were no material compliance requirements included in the report.

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.  Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed.  At present, the timing for a final rule regulating coal combustion byproducts cannot be determined, but the USEPA has stated possibly by 2014.  If coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on its operations.

Notice of Violation Involving Co-Owned Units

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

Legal andOther Matters

In February 2007, DP&L filed a lawsuit in the United States District Court for the Southern District of Ohio against Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to Appalachian’s failure to supply approximately1.5 million tons of coal to two commonly owned stations under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share.  DP&L obtained replacement coal to meet its needs.  The supplier has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor.  DP&L is unable to determine the ultimate resolution of this matter.  DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

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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.On November 28, 2011, DPL became a wholly owned subsidiary of AES, a global power company.  Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise.  Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.   

The following discussion contains forward-looking statements and should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes of DPL and the Condensed Financial Statements and related footnotes of DP&L included in Part I – Financial Information, the risk factors in Item 1A to Part I of our Form 10-K for the fiscal year ending December 31, 2012 and in Item 1A to Part II of this Quarterly Report on Form 10-Q, and our “Forward-Looking Statements” section of this Form 10-Q.  For a list of certain abbreviations or acronyms in this discussion, see the Glossary at the beginning of this Form 10-Q. 

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 11 of Notes to DPL’s Condensed Consolidated Financial Statements for more information relating to these reportable segments.  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.   

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

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers.  DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was purchased on February 28, 2011.  DPLER has approximately 247,000 customers currently located throughout Ohio and Illinois.  Approximately 86,500 of DPLER’s customers are also electric distribution customers of DP&L.  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, our captive insurance company that provides insurance services to us and our subsidiaries.  All of DPL’s subsidiaries are wholly owned. 

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

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

DPL and its subsidiaries employed 1,475 people as of March 31, 2013, of which 1,412 employees were employed by DP&L.  Approximately 53% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014.

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REGULATORY ENVIRONMENT

DPL’s, DP&L’s 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.

NO_x and SO₂  Emissions – CSAPR

The USEPA promulgated CAIR on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing power plants located in 27 eastern states, including Ohio, and the District of Columbia. CAIR contemplated two implementation phases. The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively. A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015. To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs. CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA.

In response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in these 27 States,” which is now referred to as CSAPR.  Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources in these 27 states, such as power plants.  Once fully implemented in 2014, the rule would require additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels.  Many states, utilities and other affected parties filed petitions for review, challenging CSAPR before the U.S. Court of Appeals for the District of Columbia.  A large subset of the petitioners also sought a stay of CSAPR.  On December 30, 2011, the D.C. Circuit granted a stay of CSAPR and directed the USEPA to continue administering CAIR.  On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that the USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance.  As a result of this ruling, the surviving provisions of CAIR will continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes.  Assuming that the USEPApromulgates a replacement interstate transport rule addressing the D.C. Circuit Court’s ruling, it will likely take three years from the date of promulgation before companies would be required to comply.  At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial condition, results of operations or cash flows.  On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated.  On January 24, 2013, the D.C. Circuit Court denied this petition for rehearing.  Therefore, CAIR currently remains in effect.  On March 19, 2013, the USEPA and several environmental groups filed two petitions for review of the D.C. Circuit Court’s decision with the U.S. Supreme Court.  If CSAPR were to be reinstated in its current form, we would not expect any material capital costs for DP&L’s units or stations, assuming Beckjord Unit 6 and Hutchings Station will not operate on coal in 2015 due to implementation of the MATS.  Because we cannot predict the final outcome of any replacement interstate transport rulemaking, we cannot predict its financial impact on DP&L’s operations.

Carbon Dioxide and Other Greenhouse GasEmissions

There is on-going concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly CO₂.  This concern has led to regulation and interest in legislation at the federal level, actions at the state level as well as litigation relating to GHG emissions.In 2007, a U.S. Supreme Court decision upheld that the USEPA has the authority to regulate GHG emissions under the CAA.  In April 2009, the USEPA issued a proposed endangerment finding under the CAA.  The proposed finding determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change.  This endangerment finding became effective in January 2010. 

Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding and certain GHG regulations based on that endangerment finding.  We cannot predict the outcome of this petition.  As a result of this endangerment finding and other USEPA regulations, emissions of CO₂ and other GHGs from certain EGUs and other stationary sources are subject to regulation.  Increased pressure for GHG emissions reduction is also coming from investor organizations and the international community.  Environmental advocacy groups are also focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. 

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Approximately 97.3% of the energy we produce is generated by coal.  DP&L’s share of GHG emissions at generating stations we own and co-own is approximately 14 million tons annually.  If we are required to implement control of CO₂ and other GHGs at generation facilities, the cost to DPL and DP&L of such reductions could be material.

Clean Water Act

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at theStuart Station.  The NOV indicated that construction activities caused sediment to flow into downstream creeks.  In addition, the U.S. Army Corps of Engineers issued a Cease and Desist Order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill.  The USEPA has indicated that they may take additional enforcement action.  DP&L has installed sedimentation ponds as part of the runoff control measures to address this issue and is working with the various agencies to resolve their concerns including entering into settlement discussions with the USEPA, although they have not issued any formal NOV.  On March 28, 2013, DP&L received a proposed Administrative Order from the USEPA which is currently under review by DP&L management.  This proposed order may affect the landfill’s construction schedule and delay its operational date.  DP&L has accrued an immaterial amount for anticipated penalties related to this issue.

Electric Security Plan 

SB 221 requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for their SSO.  Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements.  Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years.  An ESP may allow for adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes.  As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade, or replace its electric distribution system, including cost recovery mechanisms.  Both MRO and ESP options involve a “significantly excessive earnings test” (SEET) based on the earnings of comparable companies with similar business and financial risks.  According to DP&L’s2009 ESP stipulation,  DP&L becomes subject to the SEET in 2013 based on 2012 earnings results, and the SEET review could result in no adjustment to our SSO rates or a refund to customers.  The effect may or may not be significant. 

On October 5, 2012 DP&L filed an ESP with the PUCO to establish SSO rates that were to be in effect starting January 2013.  The plan was refiled on December 12, 2012 to correct for certain projected costs.  The plan requested approval of a non-bypassable charge that is designed to recover $137.5 million per year for five years from all customers.  DP&L also requested approval of a switching tracker that would measure the incremental amount of switching over a base case and defer the lost value into a regulatory asset which would be recovered from all customers beginning January 2014.  The ESP states that DP&L intends to file on or before December 31, 2013 its plan for legal separation of its generation assets.  The ESP proposes a three year, five month transition to market, whereby a wholesale competitive bidding structure will be phased in to supply generation service to customers located in DP&L’s service territory that have not chosen an alternative generation supplier.  DP&L’s standard offer generation revenues are projected to decrease overall as a result of this filing by approximately $46 million for the first year, due to a portion of DP&L’s SSO load being sourced through a competitive bid and other adjustments that were made to the SSO generation rates.  As more SSO supply is sourced through a competitive bid, DP&L will continue to experience a decrease in SSO generation revenues each year throughout the blending period.  DP&L’s retail transmission rates will increase as a retail, non-bypassable transmission charge will be implemented; however, this revenue is offset slightly by a decrease in wholesale transmission revenues from CRES Providers operating in DP&L’s service territory.  An evidentiary hearing on this case was held March 18, 2013 through April 3, 2013.  An order is expected to be issued by the PUCO late in the second quarter or early in the third quarter of 2013. The PUCO authorized that the rates being collected prior to December 31, 2012 would continue until the new ESP rates go into effect.

SB 221 Renewable and Energy Efficiency Requirements  

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.  The standards require that, by the year 2025, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass.  At least half of the 25% must be generated from renewable energy resources, including 0.5% from solar energy.  The renewable energy portfolio, energy efficiency and demand reduction standards began in 2009 with increased percentage requirements each year thereafter.  The annual targets for energy efficiency and peak demand reductions began in 2009 with annual increases.  Energy

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efficiency programs are expected to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to a baseline energy usage.  If any targets are not met, compliance penalties will apply, unless the PUCO makes certain findings that would excuse performance.  

COMPETITION AND PJM PRICING

RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2015/16 period cleared at a per megawatt price of $136/day for our RTO area.  The per megawatt prices for the periods 2015/16,  2014/15 and 2012/13 were $126/day, $28/day and  $16/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 2012, we estimate that a hypothetical increase or decrease of $10 in the capacity auction price would result in an annual impact to net income of approximately $5.6 million and $4.3 million for DPL and DP&L, respectively.  These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load.  These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

Ohio Competitive Considerations and Proceedings

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

Lower market prices for power have resulted in increased levels of competition to provide transmission and generation services.  This in turn has led approximately 62% of DP&L’s retail volume to be switched to CRES providers.  DPLER, an affiliated company and one of the registered CRES providers, has been marketing transmission and generation services to DP&L customers.

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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 endedMarch 31, 2013 and 2012:

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
	Electric Customers		Sales (in Millions of kWh)		Electric Customers		Sales (in Millions of kWh)
Supplied by DPLER		86,801		1,397		41,083		1,457
Supplied by non-affiliated CRES providers		84,507		822		32,656		400
Total supplied in our service territory by DPLER and other CRES providers		171,308		2,219		73,739		1,857
Distribution sales by DP&L in our service territory (a)		514,073		3,586		513,956		3,524

(a)   The volumes supplied by DPLER represent approximately 39% and 41% of DP&L’s total distribution volumes during the three months ended March 31, 2013 and 2012, respectively.  We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

For the three months endedMarch 31, 2013,  approximately 62% of DP&L’s load was supplied by CRES providers with DPLER supplying63% of the switched load.  For the three  months ended March 31, 2013, customer switching negatively affected DPL’s gross margin by approximately $51.6 million compared to the 2012 effect of approximately $27.0 million.  For the three months ended March 31, 2013, customer switching negatively affected DP&L’s gross margin by approximately $66.7 million compared to the 2012 effect of $53.0 million.

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

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, 2013, we have hedged substantially all our coal requirements to meet our committed sales.  We may not be able to hedge the entire exposure of our operations from commodity price volatility.  If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.

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RESULTS OF OPERATIONS – DPL

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

Income Statement Highlights – DPL

	Three months ended
	March 31,
$ in millions	2013		2012
Revenues:
Retail	$	331.3	$	349.3
Wholesale		38.2		22.4
RTO revenues		19.4		18.2
RTO capacity revenues		5.4		36.9
Other revenues		2.7		3.2
Other mark-to-market (losses) / gains		(2.4)		4.0
Total revenues		394.6		434.0
Cost of revenues:
Fuel costs		86.8		90.6
Losses from sale of coal		1.8		3.4
Mark-to-market losses		-		3.4
Net fuel		88.6		97.4
Purchased power		54.9		34.6
RTO charges		26.0		24.5
RTO capacity charges		6.1		33.7
Mark-to-market losses		8.3		2.0
Net purchased power		95.3		94.8
Amortization of intangibles		1.8		27.8
Total cost of revenues		185.7		220.0
Gross margins (a)	$	208.9	$	214.0
Gross margin as a percentage of revenues		53%		49%
Operating income	$	56.9	$	59.2

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

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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
	March 31,
	2013		2012
Heating degree days (a)		2,928		2,263
Cooling degree days (a)		0		30

(a)Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business.  The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit.  For example, 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.   

Sincewe 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
	March 31,
$ in millions	2013 vs. 2012
Retail
Rate		$	(23.0)
Volume			4.9
Other miscellaneous			0.1
Total retail change			(18.0)
Wholesale
Rate			(18.1)
Volume			33.9
Total wholesale change			15.8
RTO capacity & other
RTO capacity and other revenues			(30.3)
Other
Unrealized MTM			(6.4)
Other			(0.5)
Total other revenue			(6.9)
Total revenues change		$	(39.4)

For the three months ended March 31, 2013, Revenues decreased $39.4 million to $394.6 million from $434.0 million in the same period of the prior year.  This decrease was primarily the result of lower retail and wholesale

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average rates, decreased RTO capacity revenues and lower unrealized MTM gains, offset slightly by higher retail and wholesale sales volumes and increased other RTO revenues.   

· Retail revenues decreased $18.0 million primarily due to customer switching as a result of increased levels of competition to provide transmission and generation services in our service territory.  The effect of sales procured by DPLER and MC Squared outside our service territory, or off-system sales, caused sales volume to increase7%, however, the rates offered to the off-system customers are lower than the rates in our service territory causing an overall 11% decrease in average rates.  Also contributing to the increase in volume was the favorable weather; during the three months endedMarch 31, 2013 there was a 29% increase in the number of heating degree days to 2,928 days from 2,263 days in 2012.   The above resulted in an unfavorable $23.0 million retail price variance offset by a favorable $4.9 million retail sales volume variance.

· Wholesale revenues increased $15.8 million primarily as a result of a 151% increase in wholesale sales volume which was due to customer switching which makes our generation available for wholesale sales, including a 9% increase in total net generation by our power plants, offset slightly by a 32% decrease in average wholesale prices.  This resulted in a favorable $33.9 million wholesale sales volume variance offset by an unfavorable wholesale price variance of $18.1 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 $30.3 million compared to the same period in 2012.  This decrease in RTO capacity and other revenues was the result of a $31.5 million decrease in revenues realized from the PJM capacity auction, slightly offset by a $1.2 million increase in RTO transmission and congestion revenues.

DPL – Cost of Revenues  

For the three months endedMarch 31, 2013:  

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $8.8 million, or 9%, during the three months ended March 31, 2013 compared to the same period in the prior year.  This decrease was largely due to a decrease of $3.4 million in unrealized fuel MTM losses as a result of the designation of certain contracts as normal purchase, normal sale in the third quarter of 2012.  Also contributing to this decrease was a $3.8 million decrease in fuel costs due to a 12% decrease in the average fuel price per MWh, partially offset by a 9% increase in the volume of generation by our stations.  Additionally, realized losses from DP&L’s sale of coal totaled $1.8 million for the three months ended March 31, 2013, compared to $3.4 million of realized losses during the same period in the prior year, further contributing to the decrease in net fuel costs.   

· Net purchased power increased $0.5 million, or 1%, compared to the same period in the prior year due largely to an increase of $20.3 million in purchased power costs and an increase in purchased power MTM losses of $6.3 million. The increase in purchased power costs was driven by an increase in purchased power volumes of 63%, as a result of increased power purchases to supply DPLER sales, partially offset by a decrease in purchased power prices of approximately 3%.  We purchase power to satisfy retail sales volume outside of our service territory as well as inside our service territory 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.  Partially offsetting these increases was a $26.1 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers.  This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges, and is due to the lower PJM capacity auction price for the first quarter of 2013 compared to the first quarter of 2012.

· Amortization of intangibles decreased $26.0 million compared to the same period in the prior year, due primarily to the ESP intangible asset that was fully amortized as of the beginning of the first quarter of 2013.

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DPL – Operation and Maintenance   

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

	Three months ended
	March 31,
$ in millions	2013 vs. 2012
Low-income payment program (1)		$	(1.3)
Generating facilities operating and maintenance expense			(5.3)
Competitive retail operations			3.0
Other, net			1.1
Total change in operation and maintenance expense		$	(2.5)

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

During the three months ended March 31, 2013, Operation and maintenance expense decreased $2.5 million, or 2%, compared to the same period in the prior year.  This variance was primarily the result of: 

· decreased expenses for the low-income payment program which is funded by the USF revenue rate rider, and

· decreased expenses for generatingfacilities largely due to outages in the first quarter of 2012 at jointly owned production units relative to the same period in 2013, and lower partner related expenses.

These decreases were partially offset by: 

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

DPL – Depreciation and Amortization 

For the three months ended March 31, 2013, Depreciation and amortization expense increased an immaterial amount compared to the prior year.   

DPL – General Taxes 

For the three months ended March 31, 2013, General taxes decreased $0.7 million, or 3%, compared to the prior year.  This decrease was primarily the result of a 2012 property tax reserve related to the purchase accounting property revaluations partially offset by higher property tax accruals in 2013 compared to 2012.

DPL – Interest Expense   

Interest expense recorded during the three months ended March 31, 2013 did not fluctuate significantly from that recorded during the same period in the prior year.  

DPL – Income Tax Expense  

For the three months ended March 31, 2013, Income tax expense decreased $1.7 million, or 22%, compared to 2012, primarily due to decreased pre-tax income and a favorable resolution of the 2008 IRS examination in the first quarter of 2013.

RESULTS OF OPERATIONS BY SEGMENT – DPL

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

Utility Segment

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers.  Electricity for the segment’s 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 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

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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 the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier.  The Competitive Retail segment sells electricity to approximately 247,000 customers currently located throughout Ohio and Illinois.  MC Squared, a Chicago-based retail electricity supplier, serves more than 137,000 customers in Northern Illinois.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&Lin 2013 and DP&Land PJM in 2012.  DP&L sells power to DPLER and MC Squared under wholesale agreements.  Under these agreements, intercompany sales from DP&L to DPLER and MC Squared are based on fixed-price contracts for each DPLER or MC Squared customer.  The price approximates market prices for wholesale power at the inception of each customer’s contract.  The Competitive Retail segment has no transmission or generation assets.  The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Other

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

Management primarily evaluates segment performance based on gross margin. 

See Note 11  of Notes to DPL’s 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				Increase
	March 31,				(Decrease)
	2013		2012		2013 vs. 2012
Utility	$	194.3	$	219.1	$	(24.8)
Competitive retail		11.6		15.4		(3.8)
Other		3.9		(19.6)		23.5
Adjustments and eliminations		(0.9)		(0.9)		0.0
Total consolidated	$	208.9	$	214.0	$	(5.1)

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

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Income Statement Highlights – Competitive Retail Segment

	Three months ended				Increase
	March 31,				(Decrease)
$ in millions	2013		2012		2013 vs. 2012
Revenues:
Retail	$	119.7	$	107.6	$	12.1
RTO and other		(2.4)		4.5		(6.9)
Total revenues		117.3		112.1		5.2
Cost of revenues:
Purchased power		105.7		96.7		9.0
Gross margins (a)		11.6		15.4		(3.8)
Operation and maintenance expense		8.2		5.2		3.0
Other expenses		0.9		0.8		0.1
Total expenses		9.1		6.0		3.1
Earnings before income tax		2.5		9.4		(6.9)
Income tax expense		0.9		3.4		(2.5)
Net income	$	1.6	$	6.0	$	(4.4)
Gross margin as a percentage of revenues		10%		14%

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

Competitive Retail Segment – Revenue

For the three months endedMarch 31, 2013, the segment’s retail revenues increased $12.1 million, or 11%, compared to the prior year.  The increase was primarily due to increased retail sales volume from DP&L’s retail customers switching their electric service to DPLER and customer switching in Illinois and Ohio.  Increased competition in the competitive retail electric service business in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER or other CRES suppliers.  Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 2,274 million kWh of power to approximately 247,000 customers for the three months endedMarch 31, 2013 compared to approximately 1,746 million kWh of power to more than 46,000 customers during the same period of the prior year.

Competitive Retail Segment – Purchased Power 

For the three months endedMarch 31, 2013, the segment’s purchased power increased $9.0 million, or 9%, compared to 2012 due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM.

Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. 

Competitive Retail Segment – Operation and Maintenance  

For the three months endedMarch 31, 2013, DPLER’s operation and maintenance expenses included employee-related expenses, accounting, information technology, payroll, legal and other administration expenses.  The higher operation and maintenance expense in 2013 compared to 2012 is 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 endedMarch 31, 2013, the segment’s income tax expense decreased  $2.5 million compared to the same period in the prior yearprimarily due to decreased pre-tax income.

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RESULTS OF OPERATIONS – DP&L

Income Statement Highlights – DP&L 

	Three months ended
	March 31,
$ in millions	2013		2012
Revenues:
Retail	$	212.6	$	242.7
Wholesale		140.1		104.5
RTO revenues		18.8		17.3
RTO capacity revenues		4.6		31.4
Mark-to-market gains		0.4		3.7
Total revenues		376.5		399.6
Cost of revenues:
Fuel costs		86.3		88.8
Gains from sale of coal		1.8		3.4
Mark-to-market losses		-		3.4
Net fuel		88.1		95.6
Purchased power		53.3		25.5
RTO charges		25.5		24.1
RTO capacity charges		6.0		31.5
Mark-to-market losses		9.3		3.8
Total purchased power		94.1		84.9
Total cost of revenues		182.2		180.5
Gross margins (a)	$	194.3	$	219.1
Gross margin as a percentage of
revenues		52%		55%
Operating Income	$	49.6	$	65.0

(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 throughout the year include: wholesale market prices, DP&L’s retail demand and 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 period:

	Three months ended
	March 31,
$ in millions	2013 vs. 2012
Retail
Rate		$	(2.5)
Volume			(27.6)
Other miscellaneous			-
Total retail change			(30.1)
Wholesale
Rate			(34.8)
Volume			70.4
Total wholesale change			35.6
RTO capacity & other
RTO capacity and other revenues			(25.3)
Other
Unrealized MTM			(3.3)
Total other revenue			(3.3)
Total revenues change		$	(23.1)

For the three months ended March 31, 2013, Revenues decreased $23.1 million, or 6%, to $376.5 million from $399.6 million in the prior year.  This decrease was primarily the result of lower average retail and wholesale rates, lower retail sales volumes and decreased RTO capacity revenues, offset slightly by increased wholesale sales volume and increased RTO other revenues.  The revenue components for the three months ended March 31, 2013 are further discussed below: 

· Retail revenues decreased $30.1 million primarily due to an 11% decrease in retail sales volumes compared to the prior year which was a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory.  This decrease in sales volume was partially offset by colder weather.   During the three months ended March 31, 2013, there was a 29% increase in the number of heating degree days to 2,928 days from 2,263 days for the same period in the prior year.   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.  Average retail rates decreased slightly overall primarily as a result of customers switching from DP&L to DPLER.  The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates.  The above resulted in an unfavorable $27.6 million retail sales volume variance and an unfavorable $2.5 million retail price variance.  

· Wholesale revenues increased $35.6 million as a result of a 67% increase in wholesale sales volume which was largely a result 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. Also contributing was a 9% increase in net generation available from DP&L’s co-owned and operated generation plants.  These increases were partially offset by a 20% decrease in average wholesale rates.    These resulted in a favorable $70.4 million wholesale volume variance offset by a $34.8 million unfavorable wholesale price variance.  

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $25.3 million compared to the same period in 2012.  This decrease in RTO capacity and other revenues was primarily the result of a $26.8 million decrease in revenues realized from the PJM capacity auction, offset by a slight increase of $1.5 million in RTO transmission and congestion revenues. 

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DP&L – Cost of Revenues

For the three months endedMarch 31, 2013:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $7.5 million, or 8%, during the three months ended March 31, 2013 compared to the same period in the prior year.  This decrease was largely due to a decrease of $3.4 million in unrealized fuel MTM losses as a result of the designation of certain contracts as normal purchase, normal sale in the third quarter of 2012.  Also contributing to this decrease was a $2.5 million decrease in fuel costs due to an 11% decrease in the average fuel price per MWh, partially offset by a 9% increase in the volume of generation by our stations.  Additionally, realized losses from DP&L’s sale of coal totaled $1.8 million for the three months ended March 31, 2013, compared to $3.4 million of realized losses during the same period in the prior year, further contributing to the decrease in net fuel costs.   

· Net purchased power increased $9.2 million, or 11%, compared to the same period in the prior year due largely to an increase in purchased power costs of $27.8 million, or 109%, compared to the same period in the prior year, as well as an increase in unrealized purchased power MTM losses of $5.5 million.  The increase in purchased power costs was driven by an increase in purchased power volumes of 136%, as a result of increased purchased power to supply DPLER sales, partially offset by a decrease in purchased power prices of approximately 12%.  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.Partially offsetting the increase in purchased power costs and MTM losses was a $24.1 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers.  This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges, and is due to the lower PJM capacity auction price for the first quarter of 2013 compared to the first quarter of 2012.  

DP&L – Operation and Maintenance  

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

	Three months ended
	March 31,
$ in millions	2013 vs. 2012
Low-income payment program (1)		$	(1.3)
Generating facilities operating and maintenance expense			(5.2)
Other, net			(1.4)
Total change in operation and maintenance expense		$	(7.9)

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

For the three months ended March 31, 2013, Operation and maintenance expense decreased $7.9 million, or 8%, compared to the same period in the prior year.  This variance was primarily the result of: 

· decreased expenses for low-income payment program which is funded by the USF revenue rate rider,

· decreased expenses for generatingfacilities largely due to outages in the first quarter of 2012 at jointly owned production units relative to the same period in 2013, and lower partner related expenses, and

DP&L – Depreciation and Amortization 

For the three months ended March 31, 2013, Depreciation and amortization expense decreased $1.1 million compared to the prior year.  The decrease reflects the effect of the impairment in certain property, plant and equipment in the third quarter of 2012, partially offset by investments in plant and equipment during the period.

DP&L – General Taxes 

For the three months ended March 31, 2013, General taxes decreased $0.4 million, or 2%, compared to 2012.  This decrease was primarily the result of an increase in 2012 property tax reserves related to the purchase accounting property revaluations partially offset by higher property tax accruals in 2013 compared to 2012. 

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DP&L – Interest Expense  

Interest expense recorded during the three months ended March 31, 2013 did not fluctuate significantly from that recorded during the same period in the prior year.  

DP&L – Income Tax Expense 

For the three months ended March 31, 2013, Income tax expense decreased $7.7 million, or 45%, compared to 2012. The decrease was primarily due to decreased pre-tax income and a favorable resolution of the 2008 IRS examination in the first quarter of 2013.

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:

	Three months ended			Three months ended
DPL	March 31,			March 31,
$ in millions	2013			2012
Net cash from operating activities		$	106.2	$	104.0
Net cash from investing activities			(47.0)		(63.4)
Net cash from financing activities			-		(52.0)
Net change			59.2		(11.4)
Cash and cash equivalents at beginning of period			192.1		173.5
Cash and cash equivalents at end of period		$	251.3	$	162.1

	Three months ended			Three months ended
DP&L	March 31,			March 31,
$ in millions	2013			2012
Net cash from operating activities		$	101.8	$	99.0
Net cash from investing activities			(46.8)		(62.6)
Net cash from financing activities			(55.2)		(45.2)
Net change			(0.2)		(8.8)
Cash and cash equivalents at beginning of period			28.5		32.2
Cash and cash equivalents at end of period		$	28.3	$	23.4

The significant items that have affected 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. 

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DPL – Net cash from operating activities

DPL’s Net cash from operating activities for the three months endedMarch 31, 2013 and 2012is summarized as follows:

	Three months ended			Three months ended
	March 31,			March 31,
$ in millions	2013			2012
Net cash from operating activities
Net income		$	19.9	$	21.7
Depreciation and amortization			28.8		54.5
Deferred income taxes			23.3		(9.2)
Accrued interest			23.7		29.1
Deferred regulatory costs, net			3.6		7.2
Other			6.9		0.7
Net cash from operating activities		$	106.2	$	104.0

For the three months endedMarch 31, 2013, Net cash provided by operating activities was primarily a result of Net income adjusted for non-cash depreciation and amortization, deferred income taxes primarily reflecting the favorable resolution of the 2008 IRS examination and an increase in accrued interest due to the debt assumed as a result of the merger.  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 affected by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances.

For the three months endedMarch 31, 2012, Net cash provided by operating activities was primarily a result of Net income adjusted for non-cash depreciation and amortization, and an increase in accrued interest due to the debt assumed as a result of the merger.  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 affected by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances.

DP&L – Net cash from operating activities

DP&L’s Net cash from operating activities for the three months endedMarch 31, 2013 and 2012is summarized as follows:

	Three months ended			Three months ended
	March 31,			March 31,
$ in millions	2013			2012
Net cash from operating activities
Net income		$	30.2	$	38.1
Depreciation and amortization			33.6		34.7
Deferred income taxes			22.9		(2.4)
Accrued interest			2.3		7.5
Deferred regulatory costs, net			3.6		7.1
Other			9.2		14.0
Net cash from operating activities		$	101.8	$	99.0

For the three months endedMarch 31, 2013 and 2012, 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 from investing activities

DPL’s Net cash from investing activities for the three months endedMarch 31, 2013 and 2012is summarized as follows:

	Three months ended			Three months ended
	March 31,			March 31,
$ in millions	2013			2012
Net cash from investing activities
Capital expenditures		$	(33.8)	$	(54.0)
Environmental and renewable energy capital expenditures			(0.5)		(0.7)
Increase in restricted cash			(12.7)		(8.7)
Net cash from investing activities		$	(47.0)	$	(63.4)

For the three months endedMarch 31, 2013 and 2012,DPL’s cash used for investing activities was primarily for assets acquired at our generation plants. 

DP&L – Net cash from investing activities

DP&L’s Net cash from investing activities for the three months endedMarch 31, 2013 and 2012is summarized as follows:

	Three months ended			Three months ended
	March 31,			March 31,
$ in millions	2013			2012
Net cash from investing activities
Capital expenditures		$	(33.6)	$	(53.2)
Environmental and renewable energy capital expenditures			(0.5)		(0.7)
Increase in restricted cash			(12.7)		(8.7)
Net cash from investing activities		$	(46.8)	$	(62.6)

For the three months endedMarch 31, 2013 and 2012, the significant components of DP&L’s Net cash used for investing activities are similar to those discussed under DPL’s Net cash used for investing activities above.

DPL – Net cash from financing activities

DPL’s Net cash from financing activities for the three months endedMarch 31, 2013 and 2012is summarized as follows:

	Three months ended			Three months ended
	March 31,			March 31,
$ in millions	2013			2012
Net cash from financing activities
Dividends paid on common stock		$	-	$	(45.0)
Contributions to paid-in capital from parent			-		2.0
Payment to former warrant holders			-		(9.0)
Net cash from financing activities		$	-	$	(52.0)

For the three months endedMarch 31, 2013, DPLhad no cash flows related to financing activities. 

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

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DP&L – Net cash from financing activities

DP&L’s Net cash from financing activities for the three months endedMarch 31, 2013 and 2012is summarized as follows:

	Three months ended			Three months ended
	March 31,			March 31,
$ in millions	2013			2012
Net cash from financing activities
Dividends paid on common stock		$	(55.0)	$	(45.0)
Other			(0.2)		(0.2)
Net cash from financing activities		$	(55.2)	$	(45.2)

For the three months endedMarch 31, 2013 and 2012,DP&L’s Net cash used for financing activities relates to dividends paid.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs.  Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments.  For 2013, and in subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the capital markets as our internal liquidity needs and market conditions warrant.  We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods.

At the filing date of this quarterly report on Form 10-Q, DP&L has access to $400.0 million of short-term financing under two revolving credit facilities.  The first facility, established in August 2011, is for $200.0 million, expires in August 2015 and has eight participating banks, with no bank having more than 22% of the total commitment.  DP&L also has the option to increase the potential borrowing amount under the first facility by $50.0 million.  The second facility, established in April 2010, is for $200.0 million and, after an April 2013 amendment, expires in May 2013.  A total of five banks participate in this facility, with no bank having more than 35% of the total commitment.  DP&L also has the option to increase the potential borrowing amount under the second facility by $50.0 million.

At the filing date of this quarterly report on Form 10-Q, DPL has access to $75.0 million of short-term financing under a revolving credit facility established in August 2011.  This facility expires in August 2014 and has seven participating banks with no bank having more than 32% of the total commitment.See “Debt Covenants” following for more information on the amendment mentioned above. 

$ in millions	Type	Maturity	Commitment		Amounts available as of March 31, 2013
DP&L	Revolving	August 2015	$	200.0	$	200.0
DP&L	Revolving	May 2013		200.0		200.0
DPL	Revolving	August 2014		75.0		75.0
			$	475.0	$	475.0

Each DP&L revolving credit facility has a $50.0 million letter of credit sublimit.  The entire DPL revolving credit facility amount is available for letter of credit issuances.  As of March 31, 2013 and through the date of filing this quarterly report on Form 10-Q, there were no letters of credit issued and outstanding against the revolving credit facilities.

Cash and cash equivalents for DPL and DP&L amounted to $251.3 million and $28.3 million, respectively, atMarch 31, 2013.  At that date, neither DPL nor DP&L had any short-term investments that were not included in cash and cash equivalents. 

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Prior to the expiration of the DP&L amended revolving credit facility (that is now scheduled to expire on May 31, 2013) and in no case later than the end of the second quarter of 2013,DP&L intends to enter into a new $275.0 million to $350.0 million revolving credit facility and to extinguish both of the existing DP&L revolving credit facilities. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing.  The terms and conditions of this new revolving credit facility have not been finalized, but it is expected that they will be substantially similar to those of the existing DP&L revolving credit facilities.  As of the date of filing of this quarterly report on Form 10-Q, DP&L has all of the bank commitments required to close the new DP&L revolving credit facility.

On April 12, 2013, DP&L filed an application with the PUCO to approve the refinancing of its $470.0 million of First Mortgage Bonds. Subsequent to the receipt of this approval and no later than the end of the third quarter 2013, DP&L intends to access the debt capital markets to refinance these bonds.

Lastly, DP&L expects to refinance the standby letter of credit that is scheduled to expire in December 2013 and that supports the 2040 Variable Rate Demand Notes.  We currently have secured all of the bank commitments necessary to extend this facility and intend to finalize the amendment during the second quarter. The terms and conditions of this facility have not been finalized, but it is expected that the standby letter of credit will be extended for three to five years under terms that are substantially similar to those of the existing facility.

Prior to the end of the second quarter, DPL intends to enter into a new $75.0 million to $150.0 million revolving credit facility and to extinguish the existing $75.0 million facility. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing.  Contemporaneously, DPL intends to refinance a portion of its $425.0 million term loan, and repay the balance of the currently outstanding term loan with cash.  The terms and conditions of this new revolving credit facility and new term loan have not been finalized, but it is expected they will be at market for these types of transactions.  As of the date of filing this quarterly report on Form 10-Q, DPL has secured all of the bank commitments required to close the new DPL revolving credit facility and the new DPL term loan.

Capital Requirements

Planned construction additions for 2013 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. 

DPLis projecting to spend an estimated $470.0 million in capital projects for the period 2013 through 2015, of which $445.0 million is projected to be spent by DP&L.  Approximately $15.0 million of this projected amount is to enable DP&L to meet the recently revised reliability standards of NERC.  DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions of which DP&L is a member.  NERC has changed the definition of the Bulk Electric System to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply.  DP&L’s 138 kV facilities were previously not subject to these reliability standards.  Accordingly, DP&L anticipates spending approximately $72.0 million within the next five years to reinforce its 138 kV system to comply with these new NERC standards.Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds.  We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

Debt Covenants

As mentioned above, DPL has access to $75.0 million of short-term financing under its revolving credit facility and has borrowed $425.0 million under its term loan facility.   

Each of these facilities has two financial covenants, one of which was changed as part of amendments, dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups.  The first financial covenant, originally a Total Debt to Capitalization ratio, was changed, effective September 30, 2012, to a Total Debt to EBITDA ratio.  The Total Debt to EBITDA ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters.  The ratio is not to exceed 7.00 to 1.00 for the fiscal quarter ending September 30, 2012; it then steps up to not exceed 7.75 to 1.00 for the fiscal quarter ending March 31, 2013; it then steps up to not exceed 8.00 to 1.00 for the fiscal quarter ending June 30, 2013; and finally it steps up to not exceed 8.25 to 1.00 for the fiscal quarter ending September 30, 2013 and thereafter.  As of March 31, 2013, the first financial covenant was met with a ratio of 5.91 to 1.00. 

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The second financial covenant is an EBITDA to Interest Expense ratio.  The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidatedEBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.  The ratio requires DPL’s consolidated EBITDA to consolidated interest expense to be not less than 2.50 to 1.00.  As of March 31, 2013 the second covenant was met with a ratio of 3.52 to 1.00.   

The amendments, dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups restrict dividend payments from DPL to AES.  The amendments also adjusted the cost of borrowing under the facilities. 

Also mentioned above, DP&L has access to $400.0 million of short-term financing under its two revolving credit facilities.  The following financial covenant is contained in each revolving credit facility: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  As of March 31, 2013, this covenant was met with a ratio of 0.43 to 1.00.  The above ratio is calculated as the sum of DP&L’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DP&L’s shareholder’s equity and total debt including guarantee obligations.  

As part of the refinancing efforts communicated in the section above titled “Liquidity”, some of the financial covenants in the new DPL and DP&L facilities may differ from those in the existing facilities, but we expect that both DPL and DP&L will remain in compliance with any new financial covenants.

Debt Ratings

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

	DPL (a)	DP&L (b)	Outlook	Effective
Fitch Ratings	BB	BBB+	Rating Watch Negative	November 2012
Moody's Investors Service, Inc.	Ba1	A3	Under Review for Downgrade	November 2012
Standard & Poor's Financial Services LLC	BB	BBB-	Stable	April 2013

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

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

Credit Ratings

The following table outlines the credit ratings (issuer/corporate rating) and outlook for each company, along with the effective dates of each rating and outlook for DPL and DP&L. 

	DPL	DP&L	Outlook	Effective
Fitch Ratings	BB	BBB-	Rating Watch Negative	November 2012
Moody's Investors Service, Inc.	Ba1	Baa2	Under Review for Downgrade	November 2012
Standard & Poor's Financial Services LLC	BB	BB	Stable	April 2013

If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts.  These events may have an adverse effect on our results of operations, financial condition and cash flows.  In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

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Off-Balance Sheet Arrangements

DPL – Guarantees

In the normal course of business, DPL enters into various agreements with its wholly owned subsidiaries, DPLE and DPLER, and its wholly owned subsidiary MC Squared, providing financial or performance assurance to third parties.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis,thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes. During the three months endedMarch 31, 2013,  DPL did not incur any losses related to the guarantees of these obligations, and we believe it is unlikely that DPLwould be required to perform or incur any losses in the future associated with any of the above guarantees. 

At March 31, 2013, DPL had $18.0 million of guarantees to third parties, for future financial or performance assurance under such agreements, on behalf of DPLE, DPLER and MC Squared.  The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries.  The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.8 million at March 31, 2013.

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP.  As of March 31, 2013, DP&L could be responsible for the repayment of 4.9%, or $77.9 million, of a $1,588.8 million debt obligation that features maturities ranging from 2018 to 2040.  This would only happen if this electric generation company defaulted on its debt payments.  As of March 31, 2013, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2012.

Also see Note 10 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 of Notes to DP&L’s Condensed 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 2013 under contract, sales requirements may change.  The majority of the contracted coal is purchased at fixed prices.  Some contracts

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provide for periodic adjustments.  Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix.  To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January 2010, 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 at March 31, 2013 would not have a significant effect on Net income.

A 10% increase or decrease in the market price of our forward power purchase contracts with a volume of 2.2 million MWh would be $5.3 million, while a 10% increase or decrease in the market price of our forward power sale contracts with a volume of 7.1 million MWh would be $19.5 million.

Wholesale Revenues

Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER.  The following table presents the percentages of DPL’s and DP&L’s electric revenue derived from wholesale sales.

DPL	Three months ended
	March 31,
	2013		2012
Percent of electric revenues from wholesale market		11%		14%
DP&L	Three months ended
	March 31,
	2013		2012
Percent of electric revenues from wholesale market		38%		34%

The following table presents the effect on annual Net income as of March 31, 2013, 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 that 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	$	6.8	$	5.7

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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 delivery year.  The clearing prices for capacity during the PJM delivery periods from 2012/13through are as follows:

	PJM Delivery Year
($/MW-day)	2012/13		2013/14		2014/15		2015/16
Capacity clearing price	$	16	$	28	$	126	$	136

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

	Calendar Year
($/MW-day)	2012		2013		2014		2015
Computed average capacity price	$	55	$	23	$	85	$	57

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 following table provides estimates of the effect on annual Net income as of March 31, 2013 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes.  We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO.  These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through March 31, 2013.  As of March 31, 2013, approximately 39% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

$ in millions	DPL		DP&L
Effect of $10/MW-day change in capacity auction pricing	$	5.6	$	4.3

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’sfuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the three months ended March 31, 2013 and 2012were 42% and 34%,  respectively.  We have a significant portion of projected 2013 fuel needs under contract.  The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments.  We may purchase SO₂  allowances for 2013; 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 NO_x allowances for 2013 depending on NO_x emissions.  Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.

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

Effective January 1, 2010, DP&L was allowed to recover its SSO retail customers’ share of fuel and purchased power costs as part of the fuel rider approved by the PUCO.  Since there has been an increase in customer switching, SSO customers currently represent approximately 39% of DP&L’s total fuel costs.

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The following table provides the effect on annual net income as of March 31, 2013, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 39% recovery:

$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	22.0	$	20.9

Interest Rate Risk

As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates which we manage through our regular financing activities.  We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations.  DPL and DP&L have both fixed-rate and variable-rate long-term debt.  DPL’s variable-rate debt consists of a $425.0 million unsecured term loan with a syndicated bank group.  The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR.  DP&L’s variable-rate debt is comprised of publicly held pollution control bonds.  The variable-rate bonds bear interest based on a prevailing rate that is reset weekly based on a comparable market index.  Market indexes can be affected by market demand, supply, market interest rates and other economic conditions.  See Note 5 of Notes to DPL’sCondensed Consolidated Financial Statements and Note 5 to DP&L’s Condensed Financial Statements.

DPL partially hedges against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing.  As of March 31, 2013,  DPLhas entered into interest rate hedging relationships with an aggregate notional amount of $160.0 million related to planned future borrowing activities in calendar year 2013.  The average interest rate associated with the interest rate hedging relationships is 3.8%.  We are limiting our exposure to changes in interest rates since we believe the market interest rates at which we will be able to borrow in the future may increase.  Any additional credit rating downgrades could affect our liquidity and further increase our cost of capital.

Principal Payments and Interest Rate Detail by Contractual Maturity Date

The carrying value of DPL’s debt was $2,598.8 million at March 31, 2013, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base note.  All of DPL’s debt was adjusted to fair value at the Merger date according to FASC 805.  The fair value of this debt at March 31, 2013 was $2,705.4 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities.  The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes: 

DPL
													At March 31, 2013
	Twelve months ended March 31,												Principal		Fair
	2014		2015		2016		2017		2018		Thereafter		Amount		Value
Variable-rate debt	$	100.0	$	425.0	$	-	$	-	$	-	$	-	$	525.0	$	525.0
Average interest rate		0.1%		2.5%		0.0%		0.0%		0.0%		0.0%
Fixed-rate debt	$	470.4	$	0.2	$	0.1	$	450.1	$	0.2	$	1,152.8		2,073.8		2,180.4
Average interest rate		5.1%		4.8%		4.2%		6.5%		4.2%		6.6%
Total													$	2,598.8	$	2,705.4

The carrying value of DP&L’s debt was $903.2 million at March 31, 2013, consisting of its first mortgage bonds, tax-exempt pollution control bonds, capital leases and the Wright-Patterson Air Force Base note.  The fair value of this debt was $921.8 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

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information about DP&L’s debt obligations that are sensitive to interest rate changes.  DP&L’s debt was not revalued as a result of the Merger.

DP&L
													At March 31, 2013
	Twelve months ended March 31,												Principal		Fair
	2014		2015		2016		2017		2018		Thereafter		Amount		Value
Variable-rate debt	$	100.0	$	-	$	-	$	-	$	-	$	-	$	100.0	$	100.0
Average interest rate		0.0%		0.0%		0.0%		0.0%		0.0%		0.0%
Fixed-rate debt	$	470.4	$	0.2	$	0.1	$	0.1	$	0.1	$	332.3		803.2		821.8
Average interest rate		5.1%		4.8%		4.2%		4.2%		4.2%		4.8%
Total													$	903.2	$	921.8

Debt maturities occurring in 2013 are discussed under FINANCIAL CONDITION, Liquidity AND Capital ReQUIREMENTS.

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at March 31, 2013 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations, or the fair value of the debt.  We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ.  As of March 31, 2013, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

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The following tables present the carrying value and fair value of our debt, along with the impact of a change of one percent in interest rates:

DPL		At March 31, 2013			One percent
	Carrying		Fair		interest rate
$ in millions	Value		Value		risk
Long-term debt
Variable-rate debt	$	525.0	$	525.0	$	5.3
Fixed-rate debt		2,080.1		2,180.4		21.8
Total	$	2,605.1	$	2,705.4	$	27.1

DP&L		At March 31, 2013			One percent
	Carrying		Fair		interest rate
$ in millions	Value		Value		risk
Long-term debt
Variable-rate debt	$	100.0	$	100.0	$	1.0
Fixed-rate debt		803.1		821.8		8.2
Total	$	903.1	$	921.8	$	9.2

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt.  In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $2,180.4 million of fixed-rate debt and not on DPL’s financial condition or results of operations.  On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DPL’s $525.0 million variable-rate long-term debt outstanding as of March 31, 2013.

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$821.8 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations.  On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s  $100.0 million variable-rate long-term debt outstanding as of March 31, 2013.

Equity Price Risk

As of March 31, 2013,  approximately 28% of the defined benefit pension plan assets were comprised of investments in equity securities and 72% related to investments in fixed income securities, cash and cash equivalents, and alternative investments.  We use an investment adviser to assist in managing our investment portfolio.  The market value of the equity securities was approximately $102.0 million at March 31, 2013.  A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10.2 million reduction in fair value of the equity securities as of March 31, 2013.

Credit Risk

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

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Critical Accounting Estimates 

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

Different estimates could have a material effect on our financial results.  Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances.  Historically, however, recorded estimates have not differed materially from actual results.  Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.  Refer to our Form 10-K for the fiscal year ended December 31, 2012 for a complete listing of our critical accounting policies and estimates.  There have been no material changes to these critical accounting policies and estimates.

ELECTRIC SALES AND REVENUES

	DPL				DP&L (a)				DPLER (b)
	Three months ended				Three months ended				Three months ended
	March 31,				March 31,				March 31,
	2013		2012		2013		2012		2013		2012
Electric Sales (millions of kWh)		4,508		3,757		4,480		3,525		2,274		1,746
Billed electric customers (end of period)		674,479		519,167		514,089		513,972		247,191		46,278

(a)   This chart contains electric sales from DP&L’s generation and purchased power.  DP&Lsold 1,397 million kWh and 1,457 million kWh of power to DPLER during the threemonths endedMarch 31, 2013 and 2012, respectively, not included above to avoid duplication.  

(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, which is incorporated by reference into this item.

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,

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including our principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the quarter ended March 31, 2013 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Part II

Item 1.  Legal Proceedings

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

Our Form 10-K for the fiscal year ended December 31, 2012, 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 or incorporated by reference into this Item 1 to Part II of our Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Form 10-K, and should be read in conjunction with the Form 10-K.

The following information is incorporated by reference into this Item:  (i) information about DP&L’s December 12, 2012 ESP filing with the PUCO in Item 2 to Part I of this Quarterly Report on Form 10-Q; and (ii) information about the legal proceedings contained in Part I, Item 1 — Note 10 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 of Notes to DP&L’s Condensed Financial Statements of this Quarterly Report on Form 10-Q.

Item 1A.Risk Factors

A listing of the risk factors that we consider to be the most significant to a decision to invest in our securities is provided in our Form 10-K for the fiscal year ended December 31, 2012.  The information in this Item 1A to Part II of our Quarterly Report on Form 10-Q updates and restates one of the risk factors included in the Form 10-K.  Otherwise, there have been no material changes with respect to the risk factors disclosed in our form 10-K.  If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.

The risks and uncertainties described in our risk factors are not the only ones we face. In addition, new risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance.  Our risk factors should be read in conjunction with the other detailed information concerning DPL and DP&L set forth in the Notes to DPL’s and DP&L’s Financial Statements and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections included in our filings. 

The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO.

On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008.  This law, among other things, required all Ohio distribution utilities to file either an ESP or MRO, and established a SEET for Ohio public utilities that compares the utility’s earnings to the earnings of other companies with similar business and financial risks.  The PUCO approved DP&L’s filed ESP on June 24, 2009 and extended those rates until an order is issued in the currently pending ESP case.  The current ESP case will result in changes to the current rate structure and riders that could adversely affect our results of operations,

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cash flows and financial condition.  DP&L’s ESP and certain filings made by us in connection with this plan are further discussed under “Regulatory Environment” in Part 1, Item 2  – Management’s Discussion and Analysis of Financial Condition and Results of Operations. 

While rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable or that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and permitted rates of return.  Certain of our cost recovery riders are also bypassable by some of our customers who switched to a CRES provider.  Accordingly, the revenue DP&L receives may or may not match its expenses at any given time.  Therefore, DP&L could be subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of its expenses.  Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return; changes in DP&L’s rate structure, regulations regarding ownership of generation assets, transition to a competitive bid structure to supply retail generation service to SSO customers, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and other costs on a full or timely basis through rates; and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.

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

None

Item 3.  Defaults Upon Senior Securities

None

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None

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Item 6.Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X		31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)
X		32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X	X	101.INS	XBRL Instance	Furnished herewith as Exhibit 101.INS
X	X	101.SCH	XBRL Taxonomy Extension Schema	Furnished herewith as Exhibit 101.SCH
X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Furnished herewith as Exhibit 101.CAL
X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Furnished herewith as Exhibit 101.DEF
X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Furnished herewith as Exhibit 101.LAB
X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Furnished herewith as Exhibit 101.PRE

Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, we have not filed as an exhibit to this form 

10-Q certain instruments with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of us and our subsidiaries on a consolidated basis, but we hereby agree to furnish to the SEC on request any such instruments.

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SIGNATURES

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

		DPL Inc.
		The Dayton Power and Light Company
		(Registrants)
Date:	May 8, 2013	/s/ Philip R. Herrington
		(Philip R. Herrington)
		President and Chief Executive Officer
		(principal executive officer)
	May 8, 2013	/s/ Craig L. Jackson
		(Craig L. Jackson)
		Senior Vice President and Chief Financial Officer
		(principal financial officer)
	May 8, 2013	/s/ Gregory S. Campbell
		(Gregory S. Campbell)
		Vice President and Controller
		(principal accounting officer)

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EX-31.(A)

Exhibit 31(a)

CERTIFICATIONS

I, Philip Herrington, 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:  May 8, 2013

/s/ Philip R. Herrington

Philip R. Herrington

President and Chief Executive Officer

CONFIDENTIALPage 1

EX-31.(B)

Exhibit 31(b)

CERTIFICATIONS

I, Craig Jackson, 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:  May 8, 2013

/s/ Craig L. Jackson

Craig L. Jackson

Senior Vice President and Chief Financial Officer

CONFIDENTIALPage 1

EX-31.(C)

Exhibit 31(c)

CERTIFICATIONS

I, Philip Herrington, 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:  May 8, 2013

/s/ Philip R. Herrington

Philip R. Herrington

President and Chief Executive Officer

CONFIDENTIALPage 1

EX-31.(D)

Exhibit 31(d)

CERTIFICATIONS

I, Craig Jackson, 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:  May 8, 2013

/s/ Craig L. Jackson

Craig L. Jackson

Senior Vice President and Chief Financial Officer

CONFIDENTIALPage 1

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 September30, 2012, 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/ Philip R. Herrington

Philip R. Herrington

President and Chief Executive Officer

Date: May 8, 2013

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.

CONFIDENTIALPage 1

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 September30, 2012, 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/ Craig L. Jackson

Craig L. Jackson

Senior Vice President and Chief Financial Officer

Date: May 8, 2013

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.

CONFIDENTIALPage 1

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 September30, 2012, 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/ Philip R. Herrington

Philip R. Herrington

President and Chief Executive Officer

Date: May 8, 2013

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.

CONFIDENTIALPage 1

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 September30, 2012, 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/ Craig L. Jackson

Craig L. Jackson

Senior Vice President and Chief Financial Officer

Date: May 8, 2013

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.

CONFIDENTIALPage 1

XML

Supplemental Financial Information (Reclassification out of ACOI) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	$ 0.1
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(0.1)	0.6
Reclassification of earnings of Cash Flow Hedge	0.2	(0.9)
Other Comprehensive Income (Loss),Net Gain (Loss) Reclassification	0.3
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	(0.3)
Reclassification to earnings of Pension	0.3
Total Reclassifications out of AOCI	0.6
Available-for-sale Securities [Member]
Other Comprehensive Income (Loss) - Financial Instruments Reclassfication	0.1
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.1
Total Reclassifications out of AOCI	0.1
Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	0.3
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(0.1)
Reclassification of earnings of Cash Flow Hedge	0.2
Total Reclassifications out of AOCI	0.2
Other Pension Plans, Defined Benefit [Member]
Other Comprehensive Income (Loss),Net Gain (Loss) Reclassification	0.3
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	0.3
Reclassification to earnings of Pension	0.3
Total Reclassifications out of AOCI	0.3
Other Income [Member] | Available-for-sale Securities [Member]
Other Comprehensive Income (Loss) - Financial Instruments Reclassfication	0.1
Revenue [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	(0.5)
Purchased Power [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	0.8
DP&L [Member]
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	(0.1)
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.1
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(0.2)
Reclassification of earnings of Cash Flow Hedge	(0.2)
Total Reclassifications out of AOCI	(0.1)
DP&L [Member] | Available-for-sale Securities [Member]
Other Comprehensive Income (Loss) - Financial Instruments Reclassfication	0.2
Total Reclassifications out of AOCI	0.1
DP&L [Member] | Derivative [Member]
Total Reclassifications out of AOCI	(0.2)
DP&L [Member] | Other Income [Member] | Available-for-sale Securities [Member]
Other Comprehensive Income (Loss) - Financial Instruments Reclassfication	0.2
DP&L [Member] | Interest Expense [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	(0.6)
DP&L [Member] | Revenue [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	(0.5)
DP&L [Member] | Purchased Power [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	$ 1.1

XML

Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
DP&L [Member]
Total Master Trust Assets, Fair Value	$ 11.1	$ 10.6
Total Derivative Assets	6.8	7.5
Total Assets	17.9	18.1
Debt Instrument, Fair Value Disclosure	921.8	926.9
Total Derivative Liabilities	22.9	11.7
Total Liabilities	944.7	938.6
DP&L [Member] | Forward Contract Power [Member]
Total Derivative Assets	6.6	7.3
Total Derivative Liabilities	22.9	11.6
DP&L [Member] | Commodity Contract - FTR [Member]
Total Derivative Liabilities		0.1
DP&L [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets	0.2	0.2
Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	11.1	10.6
Total Derivative Assets	6.0	6.5
Total Assets	17.1	17.1
Total Derivative Liabilities	46.5	42.7
Total Liabilities	2,751.9	2,749.8
Estimate of Fair Value, Fair Value Disclosure [Member] | Forward Contract Power [Member]
Total Derivative Assets	5.8	6.3
Total Derivative Liabilities	23.3	13.1
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Contract - FTR [Member]
Total Derivative Liabilities		0.1
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets	0.2	0.2
Estimate of Fair Value, Fair Value Disclosure [Member] | Interest Rate Contract [Member]
Total Derivative Liabilities	23.2	29.5
Level 1 [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Total Derivative Assets	0.2	0.2
Total Assets	0.4	0.4
Level 1 [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets	0.2	0.2
Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Total Derivative Assets	0.2	0.2
Total Assets	0.4	0.4
Level 1 [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets	0.2	0.2
Level 2 [Member]
Total Master Trust Assets, Fair Value	10.9	10.4
Total Derivative Assets	5.8	6.3
Total Assets	16.7	16.7
Total Derivative Liabilities	46.5	42.6
Total Liabilities	2,733.1	2,730.8
Level 2 [Member] | Forward Contract Power [Member]
Total Derivative Assets	5.8	6.3
Total Derivative Liabilities	23.3	13.1
Level 2 [Member] | Interest Rate Contract [Member]
Total Derivative Liabilities	23.2	29.5
Level 2 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	10.9	10.4
Total Derivative Assets	6.6	7.3
Total Assets	17.5	17.7
Debt Instrument, Fair Value Disclosure	903.0	908.0
Total Derivative Liabilities	22.9	11.6
Total Liabilities	925.9	919.6
Level 2 [Member] | DP&L [Member] | Forward Contract Power [Member]
Total Derivative Assets	6.6	7.3
Total Derivative Liabilities	22.9	11.6
Level 3 [Member]
Total Derivative Liabilities		0.1
Total Liabilities	18.8	19.0
Level 3 [Member] | Commodity Contract - FTR [Member]
Total Derivative Liabilities		0.1
Level 3 [Member] | DP&L [Member]
Debt Instrument, Fair Value Disclosure	18.8	18.9
Total Derivative Liabilities		0.1
Total Liabilities	18.8	19.0
Level 3 [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Total Derivative Liabilities		0.1
Equity Securities [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	5.7	5.1
Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.7	5.1
Equity Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	5.7	5.1
Equity Securities [Member] | Level 2 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	5.7	5.1
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	5.7	5.1
Debt Securities [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	4.9	5.0
Debt Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	4.9	5.0
Debt Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	4.9	5.0
Debt Securities [Member] | Level 2 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	4.9	5.0
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.9	5.0
Money Market Funds [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Money Market Funds [Member] | Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Hedge Funds, Multi-strategy [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Hedge Funds, Multi-strategy [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Hedge Funds, Multi-strategy [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Hedge Funds, Multi-strategy [Member] | Level 2 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Hedge Funds, Multi-strategy [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Debt [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Debt Instrument, Fair Value Disclosure	2,705.4	2,707.1
Debt [Member] | Level 2 [Member]
Debt Instrument, Fair Value Disclosure	2,686.6	2,688.2
Debt [Member] | Level 3 [Member]
Debt Instrument, Fair Value Disclosure	$ 18.8	$ 18.9

XML

Income Taxes (Components of Income Tax Expense) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income tax expense	$ 6.0	$ 7.7
Deferred income taxes	23.3	(9.2)
Parent Company [Member]
Income tax expense	$ 6.0	$ 7.7

XML

Derivative Instruments and Hedging Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Mar. 01, 2011	Mar. 31, 2013 Not Designated as Hedging Instrument [Member]	Mar. 31, 2013 DP&L [Member]	Mar. 31, 2013 Short-term Derivative Positions [Member]	Dec. 31, 2012 Short-term Derivative Positions [Member]	Mar. 31, 2013 Long-term Derivative Positions [Member]	Dec. 31, 2012 Long-term Derivative Positions [Member]
Amount No Longer Considered Derivative	$ 5.8					$ 7.2		$ 1.0
Debt instrument interest percentage		4.20%
Fair value of commodity derivative instruments			23.3	22.9
Liability position offset by the asset position of counterparties with master netting agreements	4.5			4.5
Collateral Already Posted, Aggregate Fair Value	14.3			13.9
Collateral if debt were to fall below investment grade	4.5			4.5
Derivative Assets, Current					4.7	2.7
Derivative Assets, Noncurrent							$ 1.1	$ 3.6

XML

Debt Obligations (Long-term Debt Maturities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Due within one year	$ 570.4
Due within two years	425.2
Due within three years	0.1
Due within four years	450.1
Due within five years	0.2
Thereafter	1,152.8
Total Maturities	2,598.8
Unamortized discounts and premiums, net	(6.3)
Total	2,605.1
DP&L [Member]
Due within one year	570.4
Due within two years	0.2
Due within three years	0.1
Due within four years	0.1
Due within five years	0.1
Thereafter	332.3
Total Maturities	903.2
Unamortized discounts and premiums, net	0.1	0.1
Total	$ 903.1

XML

Summary of Significant Accounting Policies (Related Party Transactions) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
DP&L [Member]
Premiums paid for insurance services provided by MVIC	$ (0.7)	[1]	$ (0.6)	[1]
Expense recoveries for services provided to DPLER	1.1	[2]	0.9	[2]
Deposits received from DPLER	19.2	[3]
DPLE and DPLER [Member]
Sales to related party	78.7	[4]	83.0	[4]
MC Squared [Member]
Sales to related party	$ 25.6

[1] 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.

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

[3] DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity. Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.

[4] DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The decrease in DP&L’s sales to DPLER during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, is primarily due to the transfer price for the current customer base being lower than the previous year’s transfer price. The increase in DP&L’s sales to MC Squared during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, is a result of these sales beginning in September 2012.

XML

Derivative Instruments and Hedging Activities (Gains or Losses Recognized in AOCI for the Cash Flow Hedges) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended									3 Months Ended
	Mar. 31, 2013 Forward Contract Power [Member]	Mar. 31, 2012 Forward Contract Power [Member]	Mar. 31, 2013 Interest Rate Contract [Member]	Mar. 31, 2012 Interest Rate Contract [Member]	Mar. 31, 2013 DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2012 DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2013 DP&L [Member] Interest Rate Contract [Member]	Mar. 31, 2012 DP&L [Member] Interest Rate Contract [Member]	Dec. 31, 2011 DP&L [Member] Interest Rate Contract [Member]	Mar. 31, 2012 Interest Expense [Member] Interest Rate Contract [Member]	Mar. 31, 2013 Interest Expense [Member] DP&L [Member] Interest Rate Contract [Member]	Mar. 31, 2012 Interest Expense [Member] DP&L [Member] Interest Rate Contract [Member]	Mar. 31, 2013 Revenue [Member] Forward Contract Power [Member]	Mar. 31, 2012 Revenue [Member] Forward Contract Power [Member]	Mar. 31, 2013 Revenue [Member] DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2012 Revenue [Member] DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2013 Purchased Power [Member] Forward Contract Power [Member]	Mar. 31, 2012 Purchased Power [Member] Forward Contract Power [Member]	Mar. 31, 2013 Purchased Power [Member] DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2012 Purchased Power [Member] DP&L [Member] Forward Contract Power [Member]
Beginning accumulated derivative gain / (loss) in AOCI	$ (3.0)	$ 0.3	$ 0.5	$ (0.8)	$ (4.7)	$ (0.8)	$ 7.3	$ 9.2	$ 9.8
Net gains / (losses) associated with current period hedging transactions	(2.9)	(1.5)	4.1	9.1	(2.6)	(1.5)
Net gains reclassified to earnings										0.2	(0.6)	(0.6)	(0.3)	(1.2)	(0.3)	(1.2)	0.5	0.1	0.7	0.1
Ending accumulated derivative gain / (loss) in AOCI	(5.7)	(2.3)	4.6	8.5	(6.9)	(3.4)	6.7	9.2	9.8
Net gains / (losses) associated with the ineffective portion of the hedging transaction										(1.6)
Portion expected to be reclassified to earnings in the next twelve months	$ 9.9				$ 8.8
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	21 months		5 months		21 months		5 months

XML

Income Taxes (Tables)

3 Months Ended

Mar. 31, 2013

Effective Income Tax Rates

	Three months ended March 31,
	2013	2012
DPL	23.2%	26.0%

DP&L [Member]

Effective Income Tax Rates

	Three months ended March 31,
	2013	2012
DP&L	24.1%	31.3%

XML

Pension and Postretirement Benefits (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Pension [Member]
2013	$ 16.6
2014	22.5
2015	23.0
2016	23.3
2017	23.7
2018 - 2021	124.4
Postretirement [Member]
2013	1.7
2014	2.2
2015	2.0
2016	1.9
2017	1.7
2018 - 2021	6.8
DP&L [Member] | Pension [Member]
2013	16.6
2014	22.5
2015	23.0
2016	23.3
2017	23.7
2018 - 2021	124.4
DP&L [Member] | Postretirement [Member]
2013	1.7
2014	2.2
2015	2.0
2016	1.9
2017	1.7
2018 - 2021	$ 6.8

XML

Ownership of Coal-fired Facilities (Ownership Interests) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 MW
Construction Work in Process	39.0
DP&L [Member]
Construction Work in Process	31.0
DP&L Share [Member] | Beckjord Unit 6 [Member]
Ownership (%)	50.00%
Production Capacity (MW)	207
DP&L Share [Member] | Conesville Unit 4 [Member]
Ownership (%)	16.50%
Production Capacity (MW)	129
DP&L Share [Member] | East Bend Station [Member]
Ownership (%)	31.00%
Production Capacity (MW)	186
DP&L Share [Member] | Killen Station [Member]
Ownership (%)	67.00%
Production Capacity (MW)	402
DP&L Share [Member] | Miami Fort Units 7 and 8 [Member]
Ownership (%)	36.00%
Production Capacity (MW)	368
DP&L Share [Member] | Stuart Station [Member]
Ownership (%)	35.00%
Production Capacity (MW)	808
DP&L Share [Member] | Zimmer Station [Member]
Ownership (%)	28.10%
Production Capacity (MW)	365
DP&L Share [Member] | Total Jointly-owned Stations [Member]
Production Capacity (MW)	2,465
DP&L Share [Member] | Hutchings Station [Member]
Ownership (%)	100.00%
Production Capacity (MW)	365
DP&L Share [Member] | DP&L [Member] | Beckjord Unit 6 [Member]
Ownership (%)	50.00%
Production Capacity (MW)	207
DP&L Share [Member] | DP&L [Member] | Conesville Unit 4 [Member]
Ownership (%)	16.50%
Production Capacity (MW)	129
DP&L Share [Member] | DP&L [Member] | East Bend Station [Member]
Ownership (%)	31.00%
Production Capacity (MW)	186
DP&L Share [Member] | DP&L [Member] | Killen Station [Member]
Ownership (%)	67.00%
Production Capacity (MW)	402
DP&L Share [Member] | DP&L [Member] | Miami Fort Units 7 and 8 [Member]
Ownership (%)	36.00%
Production Capacity (MW)	368
DP&L Share [Member] | DP&L [Member] | Stuart Station [Member]
Ownership (%)	35.00%
Production Capacity (MW)	808
DP&L Share [Member] | DP&L [Member] | Zimmer Station [Member]
Ownership (%)	28.10%
Production Capacity (MW)	365
DP&L Share [Member] | DP&L [Member] | Total Jointly-owned Stations [Member]
Production Capacity (MW)	2,465
DP&L Share [Member] | DP&L [Member] | Hutchings Station [Member]
Ownership (%)	100.00%
Production Capacity (MW)	365
DP&L Investment [Member] | Beckjord Unit 6 [Member]
Gross Plant In Service	1.0
Accumulated Depreciation	1.0
SCR and FGD Equipment Installed and In Service	No
DP&L Investment [Member] | Conesville Unit 4 [Member]
Gross Plant In Service	42.0
Accumulated Depreciation	4.0
Construction Work in Process	12.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | East Bend Station [Member]
Gross Plant In Service	8.0
Accumulated Depreciation	3.0
Construction Work in Process	3.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Killen Station [Member]
Gross Plant In Service	301.0
Accumulated Depreciation	4.0
Construction Work in Process	9.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Miami Fort Units 7 and 8 [Member]
Gross Plant In Service	212.0
Accumulated Depreciation	9.0
Construction Work in Process	3.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Stuart Station [Member]
Gross Plant In Service	202.0
Accumulated Depreciation	7.0
Construction Work in Process	10.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Zimmer Station [Member]
Gross Plant In Service	169.0
Accumulated Depreciation	15.0
Construction Work in Process	2.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Total Jointly-owned Stations [Member]
Gross Plant In Service	975.0
Accumulated Depreciation	45.0
Construction Work in Process	39.0
DP&L Investment [Member] | Transmission (At Varying Percentages) [Member]
Gross Plant In Service	40.0
Accumulated Depreciation	2.0
DP&L Investment [Member] | Hutchings Station [Member]
SCR and FGD Equipment Installed and In Service	No
DP&L Investment [Member] | DP&L [Member] | Beckjord Unit 6 [Member]
Gross Plant In Service	76.0
Accumulated Depreciation	64.0
SCR and FGD Equipment Installed and In Service	No
DP&L Investment [Member] | DP&L [Member] | Conesville Unit 4 [Member]
Gross Plant In Service	28.0
Accumulated Depreciation	2.0
Construction Work in Process	4.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | East Bend Station [Member]
Gross Plant In Service	209.0
Accumulated Depreciation	137.0
Construction Work in Process	3.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Killen Station [Member]
Gross Plant In Service	617.0
Accumulated Depreciation	302.0
Construction Work in Process	9.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Miami Fort Units 7 and 8 [Member]
Gross Plant In Service	361.0
Accumulated Depreciation	148.0
Construction Work in Process	3.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Stuart Station [Member]
Gross Plant In Service	744.0
Accumulated Depreciation	297.0
Construction Work in Process	10.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Zimmer Station [Member]
Gross Plant In Service	1,097.0
Accumulated Depreciation	644.0
Construction Work in Process	2.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Total Jointly-owned Stations [Member]
Gross Plant In Service	3,229.0
Accumulated Depreciation	1,653.0
Construction Work in Process	31.0
DP&L Investment [Member] | DP&L [Member] | Transmission (At Varying Percentages) [Member]
Gross Plant In Service	97.0
Accumulated Depreciation	59.0
DP&L Investment [Member] | DP&L [Member] | Hutchings Station [Member]
SCR and FGD Equipment Installed and In Service	No

XML

Supplemental Financial Information (Supplemental Financial Information) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Unbilled revenue	$ 65.3	$ 75.2
Customer receivables	107.5	98.2
Amounts due from partners in jointly owned stations	15.3	19.7
Coal sales		1.6
Other	3.1	14.6
Provision for uncollectible accounts	(1.1)	(1.1)
Total accounts receivable, net	190.1	208.2
Fuel and Limestone	72.0	67.3
Plant materials and supplies	40.6	41.0
Other	1.9	1.8
Total inventories, at average cost	114.5	110.1
DP&L [Member]
Unbilled revenue	41.6	48.1
Customer receivables	68.3	62.0
Amounts due from partners in jointly owned stations	15.3	19.7
Coal sales		1.6
Other	24.0	29.5
Provision for uncollectible accounts	(1.0)	(0.9)
Total accounts receivable, net	148.2	160.0
Fuel and Limestone	71.9	67.3
Plant materials and supplies	39.4	39.8
Other	1.9	1.8
Total inventories, at average cost	$ 113.2	$ 108.9

XML

Fair Value Measurements (Fair Value and Cost of Non-Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
DP&L [Member]
Total Master Trust Assets, Cost	$ 9.0	$ 9.1
Total Master Trust Assets, Fair Value	11.1	10.6
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost		9.1
Total Assets	9.0
Fair Value [Member]
Total Assets	11.1	10.6
Equity Securities [Member] | DP&L [Member]
Total Master Trust Assets, Cost	4.0	4.0
Total Master Trust Assets, Fair Value	5.7	5.1
Equity Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	4.0	4.0
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	5.7	5.1
Debt Securities [Member] | DP&L [Member]
Total Master Trust Assets, Cost	4.5	4.6
Total Master Trust Assets, Fair Value	4.9	5.0
Debt Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	4.5	4.6
Debt Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	4.9	5.0
Hedge Funds, Multi-strategy [Member] | DP&L [Member]
Total Master Trust Assets, Cost	0.3	0.3
Total Master Trust Assets, Fair Value	0.3	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] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.3	0.3
Money Market Funds [Member] | DP&L [Member]
Total Master Trust Assets, Cost	0.2	0.2
Total Master Trust Assets, Fair Value	0.2	0.2
Money Market Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.2	0.2
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.2	0.2
Debt [Member] | DP&L [Member]
Debt, Cost	903.1	903.1
Debt, Fair Value	921.8	926.9
Debt [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Debt, Cost	2,605.1	2,609.9
Debt [Member] | Fair Value [Member]
Debt, Fair Value	$ 2,705.4	$ 2,707.1

XML

Common Shareholders' Equity (Details) (DP&L [Member])	3 Months Ended
	Mar. 31, 2013
DP&L [Member]
Common stock, shares authorized	250,000,000
Common stock, shares outstanding	41,172,173
PUCO Meger Equity Ratio Approval	50.00%

XML

Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Estimated annual effective income tax rate	30.20%	25.60%
Tax Refund	$ 19.9
Decrease in income tax expense	1.2
Increase (decrease) in deferred tax liabilities	23.3
Additional tax decrease	1.2
Effective income tax rates	23.20%	26.00%
DP&L [Member]
Estimated annual effective income tax rate	28.80%	31.10%
Increase (decrease) in deferred tax liabilities	$ 21.3
Effective income tax rates	24.10%	31.30%

XML

Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2013

Regulatory Matters

3.  Regulatory Assets and Liabilities 

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

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

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

Regulatory assets and liabilities for DPL are as follows:  

$ in millions	Type of Recovery (a)	Amortization through	At March 31, 2013		At December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	6.6	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		11.4		14.1
Total regulatory assets, current			$	18.0	$	21.1
Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	34.3	$	35.1
Pension benefits	C	Ongoing		87.3		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.7		11.9
Regional transmission organization costs	D	2014		2.2		2.6
Deferred storm costs	D			24.7		24.4
CCEM smart grid and advanced metering infrastructure costs	D			6.6		6.6
CCEM energy efficiency program costs	F	Ongoing		3.4		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.6		4.7
Total regulatory assets, non-current			$	180.9	$	185.5
Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.6	$	112.1
Postretirement benefits				4.8		5.0
Other				0.4		0.2
Total regulatory liabilities, non-current			$	118.8	$	117.3

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

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

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

F – Recovery of incurred costs plus rate of return. 

Regulatory Assets 

TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM.  On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.   

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider.  The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter.  DP&L implemented the fuel and purchased power recovery rider on January 1, 2010.  As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process.  

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

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

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

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

Deferred storm costs relate to costs incurred to repair the damage caused by storms in the following years:

· 2008 – related to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other 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.

· 2011 – related to five major storms in 2011.  On December 21, 2012, DP&L filed a request with the PUCO for an accounting order to defer costs and a request for recovery of costs associated with these storms.  At March 31, 2013, DP&L believes the recovery of these costs is probable.

· 2012 – related to storm damage that occurred during the final weekend of June 2012.  On August 10, 2012, DP&L filed a request with the PUCO, which was modified on October 19, 2012, for an accounting order to defer the costs associated with this storm damage.  On December 19, 2012, the PUCO issued an order permitting partial deferral. 

On December 21, 2012, DP&L filed a request for recovery of all of these deferred storm costs with the PUCO.

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 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.  On April 29, 2011, DP&L filed to true-up the energy efficiency rider which was approved by the PUCO on October 18, 2011.  DP&Lmade its true-up filing on April 30, 2013.

Consumer education campaign represents costs for consumer education advertising regarding electric deregulation.  DP&L will be seeking recovery of these costs as part of our next distribution rate case filing at the PUCO.  The timing of such a filing has not yet been determined. 

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

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

Regulatory Liabilities 

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

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

DP&L [Member]

Regulatory Matters

3.  Regulatory Assets and Liabilities 

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

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

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

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

$ in millions	Type of Recovery (a)	Amortization through	At March 31, 2013		At December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	6.6	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		10.0		11.3
Total regulatory assets, current			$	16.6	$	18.3
Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	34.3	$	35.1
Pension benefits	C	Ongoing		87.3		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.7		11.9
Regional transmission organization costs	D	2014		2.2		2.6
Deferred storm costs	D			24.7		24.4
CCEM smart grid and advanced metering infrastructure costs	D			6.6		6.6
CCEM energy efficiency program costs	F	Ongoing		3.4		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.6		4.7
Total regulatory assets, non-current			$	180.9	$	185.5
Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.6	$	112.1
Postretirement benefits				4.8		5.0
Other				0.4		0.2
Total regulatory liabilities, non-current			$	118.8	$	117.3

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

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

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

F – Recovery of incurred costs plus rate of return. 

Regulatory Assets 

TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM.  On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.   

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider.  The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter.  DP&L implemented the fuel and purchased power recovery rider on January 1, 2010.  As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process.  

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

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

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

Regional transmission organization costs represent costs incurred to join an RTO.  The recovery of these costs will be requested in a future FERC rate case.   

Deferred storm costs relate to costs incurred to repair the damage caused by storms in the following years:

· 2008 – related to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other 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.

· 2011 – related to five major storms in 2011.  On December 21, 2012, DP&L filed a request with the PUCO for an accounting order to defer costs and a request for recovery of costs associated with these storms.  At March 31, 2013, DP&L believes the recovery of these costs is probable.

· 2012 – related to storm damage that occurred during the final weekend of June 2012.  On August 10, 2012, DP&L filed a request with the PUCO, which was modified on October 19, 2012, for an accounting order to defer the costs associated with this storm damage.  On December 19, 2012, the PUCO issued an order permitting partial deferral. 

On December 21, 2012, DP&L filed a request for recovery of all of these deferred storm costs with the PUCO.

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.  On April 29, 2011, DP&L filed to true-up the energy efficiency rider which was approved by the PUCO on October 18, 2011.  DP&Lmade its true-up filing on April 30, 2013. 

Consumer education campaign represents costs for consumer education advertising regarding electric deregulation.  DP&L will be seeking recovery of these costs as part of our next distribution rate case filing at the PUCO.  The timing of such a filing has not yet been determined. 

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

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

Regulatory Liabilities 

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

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

XML

Commitments, Environmental, Legal (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013 T	Mar. 01, 2011
Public Utility, Property, Plant and Equipment [Line Items]
Third party guarantees	$ 18,000,000
Due to third parties, current	800,000
Debt instrument interest percentage		4.20%
Environmental reserves	3,100,000
Percentage of energy generated by coal	97.00%
Annual CO2 emissions generation at stations, in tons	14,000,000
CO2 tons per megawatt-hour for USEPA standard on new EGUs	1,000
Number of Auxiliary Boilers	7
Relief and civil penalties, per day	27,500
DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Equity ownership interest	4.90%
Long Term Debt Date Range Equity Ownership, Start	2018
Long Term Debt Date Range Equity Ownership, End	2040
Percentage of energy generated by coal	97.00%
Number of tons of CO2 emitted per year including electric generating units	14,000,000
CO2 tons per megawatt-hour for USEPA standard on new EGUs	1,000
Relief and civil penalties, per day	27,500
Coal supply failure by suppliers	570,000
Electric Generation Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt obligation	1,588,800,000
DPLE and DPLER [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Third party guarantees	17,700,000
MC Squared [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Third party guarantees	300,000
Beckjord Unit 6 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of coal-fire power plant holdings	50.00%
Hutchings Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Percentage of coal-fire power plant holdings	100.00%
Coal Supply Agreements [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Coal supply failure by suppliers	1,500,000
Coal Supply Agreements [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Coal supply failure by suppliers	1,500,000
Coal supply agreement, in tons	570,000
Debt Obligation on 4.9% Equity Ownership [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Equity ownership interest	4.90%
Equity ownership interest aggregate cost	77,900,000
Long Term Debt Date Range Equity Ownership, Start	2018
Long Term Debt Date Range Equity Ownership, End	2040
Debt Obligation on 4.9% Equity Ownership [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt obligation	$ 77,900,000
First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	5.125%
First Mortgage Bonds Maturing in October 2013 - 5.125% [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	5.125%
Pollution Control Series Maturing in January 2028 - 4.70% [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.70%
Pollution Control Series Maturing in January 2028 - 4.70% [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.70%
Pollution Control Series Maturing in January 2034 - 4.80% [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.80%
Pollution Control Series Maturing in January 2034 - 4.80% [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.80%
Pollution Control Series Maturing in September 2036 - 4.80% [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.80%
Pollution Control Series Maturing in September 2036 - 4.80% [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.80%
U.S. Government note maturing in February 2061 - 4.20% [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.20%
U.S. Government note maturing in February 2061 - 4.20% [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	4.20%	4.20%
Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	8.125%
Five Year Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	6.50%
Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Debt instrument interest percentage	7.25%
NOx [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Emission Reductions	54.00%
NOx [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Emission Reductions	54.00%
SO2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Emission Reductions	73.00%
SO2 [Member] | DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Emission Reductions	73.00%

XML

Debt Obligations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended					3 Months Ended			3 Months Ended			1 Months Ended		3 Months Ended			1 Months Ended	3 Months Ended			3 Months Ended		3 Months Ended				3 Months Ended		3 Months Ended
	Oct. 31, 2012	Mar. 31, 2013	Mar. 01, 2011	Dec. 04, 2008	Mar. 31, 2013 DP&L [Member]	Dec. 04, 2008 DP&L [Member]	Mar. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member]	Dec. 31, 2012 U.S. Government note maturing in February 2061 - 4.20% [Member]	Mar. 01, 2011 U.S. Government note maturing in February 2061 - 4.20% [Member]	Mar. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Dec. 31, 2012 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Mar. 01, 2011 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Oct. 31, 2012 Revolving Credit Agreement with Bank Group [Member]	Aug. 31, 2011 Revolving Credit Agreement with Bank Group [Member]	Apr. 20, 2010 Revolving Credit Agreement with Bank Group [Member]	Mar. 31, 2013 Revolving Credit Agreement with Bank Group [Member]	Aug. 24, 2011 Revolving Credit Agreement with Bank Group [Member]	Aug. 24, 2011 Revolving Credit Agreement with Bank Group [Member] DP&L [Member]	Apr. 20, 2010 Revolving Credit Agreement with Bank Group [Member] DP&L [Member]	Mar. 31, 2013 Revolving Credit Agreement with Bank Group [Member] DP&L [Member]	Mar. 31, 2013 Revolving Credit Agreement with Bank Group [Member] DPL [Member]	Mar. 31, 2013 Five Year Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Dec. 31, 2012 Five Year Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Mar. 31, 2013 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Dec. 31, 2012 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Mar. 31, 2013 First Mortgage Bonds Maturing October 2013 [Member]	Mar. 31, 2013 First Mortgage Bonds Maturing October 2013 [Member] DP&L [Member]	Mar. 31, 2013 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Dec. 31, 2012 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Mar. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Mar. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Mar. 31, 2013 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]	Dec. 31, 2012 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]	Aug. 24, 2011 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]
Additional principal amount of senior notes to be raised		$ 1,250.0																				$ 450.0		$ 800.0
Debt instrument maturity date																						Oct. 15, 2016		Oct. 15, 2021
Debt Instrument, Maturity Date Range, End							Feb. 01, 2061			Feb. 01, 2061												Oct. 01, 2016		Oct. 01, 2021				Sep. 01, 2031		Nov. 01, 2040	Nov. 01, 2040	Aug. 01, 2014
Unsecured revolving credit agreement														125.0	200.0	125.0	200.0	200.0	200.0
Future Line Of Credit Facility Minimum Borrowing Capacity					275.0															275.0	75.0
Future line of credit facility maximum borrowing capacity					350.0															350.0	150.0
Increase additional facility														50.0	50.0			50.0	50.0
Decrease additional facility	75.0												75.0
Letter of credit sublimit													75.0	50.0	50.0			50.0	50.0
Collateralized debt				100.0		100.0
Long-term Debt, Gross							$ 18.3	$ 18.3	$ 18.7	$ 18.3	$ 18.3	$ 18.7										$ 450.0	$ 450.0	$ 800.0	$ 800.0	$ 470.0	$ 470.0	$ 19.6	$ 19.6			$ 425.0	$ 425.0	$ 425.0
Debt instrument interest percentage			4.20%				4.20%			4.20%		4.20%										6.50%		7.25%				8.125%

XML

Business Segments (Tables)

3 Months Ended

Mar. 31, 2013

Mar. 31, 2012

Business Segments [Abstract]

Financial Reporting for Reportable Business Segments

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended March 31, 2013
Revenues from external customers	$	271.8	$	117.3	$	5.5	$	-	$	394.6
Intersegment revenues		104.7		-		0.9		(105.6)		-
Total revenues		376.5		117.3		6.4		(105.6)		394.6
Fuel		88.1		-		0.5		-		88.6
Purchased power		94.1		105.7		0.2		(104.7)		95.3
Amortization of intangibles		-		-		1.8		-		1.8
Gross margin	$	194.3	$	11.6	$	3.9	$	(0.9)	$	208.9
Depreciation and amortization	$	33.6	$	0.1	$	(1.9)	$	-	$	31.8
Interest expense		9.3		0.2		21.2		(0.2)		30.5
Income tax expense (benefit)		9.6		0.9		(4.5)		-		6.0
Net income / (loss)		30.2		1.6		(11.9)		-		19.9
Cash capital expenditures		33.6		-		0.2		-		33.8
At March 31, 2013
Total assets	$	3,439.6	$	95.8	$	738.9	$	-	$	4,274.3

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended March 31, 2012
Revenues from external customers	$	312.8	$	112.1	$	9.1	$	-	$	434.0
Intersegment revenues		86.8		-		0.9		(87.7)		-
Total revenues		399.6		112.1		10.0		(87.7)		434.0
Fuel		95.6		-		1.8		-		97.4
Purchased power		84.9		96.7		-		(86.8)		94.8
Amortization of intangibles		-		-		27.8		-		27.8
Gross margin	$	219.1	$	15.4	$	(19.6)	$	(0.9)	$	214.0
Depreciation and amortization	$	34.7	$	0.2	$	(3.5)	$	-	$	31.4
Interest expense		9.6		0.2		20.0		(0.2)		29.6
Income tax expense (benefit)		17.3		3.4		(13.0)		-		7.7
Net income / (loss)		38.1		6.0		(22.4)		-		21.7
Cash capital expenditures		53.2		0.4		0.4		-		54.0
At December 31, 2012
Total assets	$	3,464.2	$	99.2	$	683.9	$	-	$	4,247.3

XML

Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

12 Months Ended

15 Months Ended

Mar. 31, 2013

Mar. 31, 2012

Dec. 31, 2012

Mar. 31, 2013

Schedule of Notional Amounts of Outstanding Derivative Positions

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		2.8		-		2.8
Heating Oil Futures		Mark to Market	Gallons		1,890.0		-		1,890.0
Forward Power Contracts		Cash Flow Hedge	MWh		842.6		(2,040.9)		(1,198.3)
Forward Power Contracts		Mark to Market	MWh		2,221.4		(7,069.8)		(4,848.4)
Interest Rate Swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating Oil Futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward Power Contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward Power Contracts		Mark to Market	MWh		2,510.7		(4,760.4)		(2,249.7)
Interest Rate Swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(3.0)	$	0.5	$	0.3	$	(0.8)
Net gains / (losses) associated with current period hedging transactions		(2.9)		4.1		(1.5)		9.1
Net gains reclassified to earnings
Interest Expense		-		-		-		0.2
Revenues		(0.3)		-		(1.2)		-
Purchased Power		0.5		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	(5.7)	$	4.6	$	(2.3)	$	8.5
Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest Expense	$	-	$	-	$	-	$	(1.6)
Revenues	$	-	$	-	$	-	$	-
Purchased Power	$	-	$	-	$	-	$	-
Portion expected to be reclassified to earnings in the next twelve months (a)	$	9.9	$	-
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21		5

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

For the three months ended March 31, 2013
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	-	$	-	$	-	$	(16.5)	$	(16.5)
Realized gain / (loss)		-		-		0.5		0.4		0.9
Total	$	-	$	-	$	0.5	$	(16.1)	$	(15.6)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	-	$	-	$	-	$	-	$	-
Regulatory (asset) / liability		-		-		-		-		-
Recorded in Income Statement:  gain / (loss)
Revenue		-		-		-		-		-
Purchased Power		-		-		0.5		(16.1)		(15.6)
Fuel		-		-		-		-		-
O&M		-		-		-		-		-
Total	$	-	$	-	$	0.5	$	(16.1)	$	(15.6)

For the three months ended March 31, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(7.8)	$	(0.1)	$	(0.1)	$	1.4	$	(6.6)
Realized gain / (loss)		(5.0)		0.9		(0.2)		(2.3)		(6.6)
Total	$	(12.8)	$	0.8	$	(0.3)	$	(0.9)	$	(13.2)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	(3.5)	$	-	$	-	$	-	$	(3.5)
Regulatory (asset) / liability		(1.1)		0.1		-		-		(1.0)
Recorded in Income Statement:  gain / (loss)
Revenue		-		-		-		3.4		3.4
Purchased Power		-		-		(0.3)		(4.3)		(4.6)
Fuel		(8.2)		0.6		-		-		(7.6)
O&M		-		0.1		-		-		0.1
Total	$	(12.8)	$	0.8	$	(0.3)	$	(0.9)	$	(13.2)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Fair Values of Derivative Instruments
at March 31, 2013
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.2	$	(0.1)	$	-	$	0.1
Forward Power Contracts	MTM		4.5		(3.8)		-		0.7
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	MTM		1.1		(0.6)		-		0.5
Total assets		$	6.0	$	(4.5)	$	(0.2)	$	1.3
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	8.9	$	(0.1)	$	(6.2)	$	2.6
Interest Rate Hedge	Cash Flow		23.2		-		-		23.2
Forward Power Contracts	MTM		9.9		(3.8)		(5.5)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.9		-		(1.1)		0.8
Forward Power Contracts	MTM		2.6		(0.6)		(1.5)		0.5
Total liabilities		$	46.5	$	(4.5)	$	(14.3)	$	27.7

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward Power Contracts	MTM		2.7		(1.5)		-		1.2
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	Cash Flow		0.5		(0.5)		-		-
Forward Power Contracts	MTM		3.6		(0.6)		-		3.0
Total assets		$	7.5	$	(3.1)	$	(0.2)	$	4.2
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
Interest Rate Hedge	Cash Flow		29.5		-		-		29.5
FTRs	MTM		0.1		-		-		0.1
Forward Power Contracts	MTM		4.1		(1.5)		(2.0)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward Power Contracts	MTM		0.8		(0.6)		(0.1)		0.1
Total liabilities		$	42.7	$	(3.1)	$	(5.1)	$	34.5

DP&L [Member]

Schedule of Notional Amounts of Outstanding Derivative Positions

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		2.8		-		2.8
Heating Oil Futures		Mark to Market	Gallons		1,890.0		-		1,890.0
Forward Power Contracts		Cash Flow Hedge	MWh		842.6		(2,040.9)		(1,198.3)
Forward Power Contracts		Mark to Market	MWh		2,221.4		(7,069.8)		(4,848.4)

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating Oil Futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward Power Contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward Power Contracts		Mark to Market	MWh		2,296.6		(4,760.4)		(2,463.8)

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(4.7)	$	7.3	$	(0.8)	$	9.8
Net gains / (losses) associated with current period hedging transactions		(2.6)		-		(1.5)		-
Net gains reclassified to earnings
Interest Expense		-		(0.6)		-		(0.6)
Revenues		(0.3)		-		(1.2)		-
Purchased Power		0.7		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	(6.9)	$	6.7	$	(3.4)	$	9.2
Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest Expense	$	-	$	-
Revenues	$	-	$	-
Purchased Power	$	-	$	-
Portion expected to be reclassified to earnings in the next twelve months (a)	$	8.8	$	-
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21		5

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

For the three months ended March 31, 2013
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	-	$	-	$	-	$	(10.4)	$	(10.4)
Realized gain / (loss)		-		-		0.5		0.7		1.2
Total	$	-	$	-	$	0.5	$	(9.7)	$	(9.2)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	-	$	-	$	-	$	-	$	-
Regulatory (asset) / liability		-		-		-		-		-
Recorded in Income Statement: gain / (loss)
Revenue		-		-		-		(1.1)		(1.1)
Purchased Power		-		-		0.5		(8.6)		(8.1)
Fuel		-		-		-		-		-
O&M		-		-		-		-		-
Total	$	-	$	-	$	0.5	$	(9.7)	$	(9.2)

For the three months ended March 31, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(7.8)	$	(0.1)	$	(0.1)	$	-	$	(8.0)
Realized gain / (loss)		(5.0)		0.9		(0.2)		-		(4.3)
Total	$	(12.8)	$	0.8	$	(0.3)	$	-	$	(12.3)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	(3.5)	$	-	$	-	$	-	$	(3.5)
Regulatory (asset) / liability		(1.1)		0.1		-		-		(1.0)
Recorded in Income Statement: gain / (loss)
Revenue		-		-		-		1.6		1.6
Purchased Power		-		-		(0.3)		(1.6)		(1.9)
Fuel		(8.2)		0.6		-		-		(7.6)
O&M		-		0.1		-		-		0.1
Total	$	(12.8)	$	0.8	$	(0.3)	$	-	$	(12.3)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Fair Values of Derivative Instruments
at March 31, 2013
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.2	$	(0.1)	$	-	$	0.1
Forward Power Contracts	MTM		5.3		(3.8)		-		1.5
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	MTM		1.1		(0.6)		-		0.5
Total assets		$	6.8	$	(4.5)	$	(0.2)	$	2.1
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	8.9	$	(0.1)	$	(6.2)	$	2.6
Forward Power Contracts	MTM		9.5		(3.8)		(5.1)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.9		-		(1.1)		0.8
Forward Power Contracts	MTM		2.6		(0.6)		(1.5)		0.5
Total liabilities		$	22.9	$	(4.5)	$	(13.9)	$	4.5

Fair Values of Derivative Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward Power Contracts	MTM		2.8		(1.5)		-		1.3
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	Cash Flow		0.5		(0.5)		-		-
Forward Power Contracts	MTM		3.6		(0.6)		-		3.0
Total assets		$	7.6	$	(3.1)	$	(0.2)	$	4.3
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
FTRs	MTM		0.1		-		-		0.1
Forward Power Contracts	MTM		2.7		(1.5)		(0.5)		0.7
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward Power Contracts	MTM		0.7		(0.6)		-		0.1
Total liabilities		$	11.7	$	(3.1)	$	(3.5)	$	5.1

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Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2013 MWh	Dec. 31, 2012 MWh
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Purchase of Derivative Instruments Interest Rate Swaps	160,000,000	160,000,000
Notional Amount of Derivatives	160,000,000	160,000,000
Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	842,600	1,021,000
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(2,040,900)	(2,197,900)
Derivative, Nonmonetary Notional Amount MWh	(1,198,300)	(1,176,900)
Designated as Hedging Instrument [Member] | DP&L [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	842,600	1,021,000
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(2,040,900)	(2,197,900)
Derivative, Nonmonetary Notional Amount MWh	(1,198,300)	(1,176,900)
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	2,800	6,900
Derivative, Nonmonetary Notional Amount MWh	2,800	6,900
Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member]
Purchase of Volume Units Derivative Instruments Heating Oil Futures	1,890,000	1,764,000
Derivative, Nonmonetary Notional Amount Volume	1,890,000	1,764,000
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	2,221,400	2,510,700
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(7,069,800)	(4,760,400)
Derivative, Nonmonetary Notional Amount MWh	(4,848,400)	(2,249,700)
Not Designated as Hedging Instrument [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	2,800	6,900
Derivative, Nonmonetary Notional Amount MWh	2,800	6,900
Not Designated as Hedging Instrument [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Purchase of Volume Units Derivative Instruments Heating Oil Futures	1,890,000	1,764,000
Derivative, Nonmonetary Notional Amount Volume	1,890,000	1,764,000
Not Designated as Hedging Instrument [Member] | DP&L [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	2,221,400	2,296,600
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(7,069,800)	(4,760,400)
Derivative, Nonmonetary Notional Amount MWh	(4,848,400)	(2,463,800)

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Debt Obligations (Long-term Debt) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended						3 Months Ended				3 Months Ended		3 Months Ended		3 Months Ended		3 Months Ended		3 Months Ended		3 Months Ended							3 Months Ended			3 Months Ended				3 Months Ended		3 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 01, 2011	Mar. 31, 2013 DP&L [Member]		Dec. 31, 2012 DP&L [Member]		Mar. 31, 2013 First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]	Mar. 31, 2013 First Mortgage Bonds Maturing in October 2013 - 5.125% [Member] DP&L [Member]	Mar. 31, 2013 Pollution Control Series Maturing in January 2028 - 4.70% [Member]	Dec. 31, 2012 Pollution Control Series Maturing in January 2028 - 4.70% [Member]	Mar. 31, 2013 Pollution Control Series Maturing in January 2028 - 4.70% [Member] DP&L [Member]	Dec. 31, 2012 Pollution Control Series Maturing in January 2028 - 4.70% [Member] DP&L [Member]	Mar. 31, 2013 Pollution Control Series Maturing in January 2034 - 4.80% [Member]	Dec. 31, 2012 Pollution Control Series Maturing in January 2034 - 4.80% [Member]	Mar. 31, 2013 Pollution Control Series Maturing in January 2034 - 4.80% [Member] DP&L [Member]	Dec. 31, 2012 Pollution Control Series Maturing in January 2034 - 4.80% [Member] DP&L [Member]	Mar. 31, 2013 Pollution Control Series Maturing in September 2036 - 4.80% [Member]	Dec. 31, 2012 Pollution Control Series Maturing in September 2036 - 4.80% [Member]	Mar. 31, 2013 Pollution Control Series Maturing in September 2036 - 4.80% [Member] DP&L [Member]	Dec. 31, 2012 Pollution Control Series Maturing in September 2036 - 4.80% [Member] DP&L [Member]	Mar. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Mar. 31, 2012 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Mar. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Mar. 31, 2012 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Mar. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member]	Dec. 31, 2012 U.S. Government note maturing in February 2061 - 4.20% [Member]	Mar. 01, 2011 U.S. Government note maturing in February 2061 - 4.20% [Member]	Mar. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Dec. 31, 2012 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Mar. 01, 2011 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Mar. 31, 2013 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]	Mar. 31, 2012 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]	Dec. 31, 2012 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]	Aug. 24, 2011 Bank Term Loan - variable rates: 2.22% - 2.30% and 1.48% - 4.25% [Member]	Mar. 31, 2013 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Dec. 31, 2012 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Mar. 31, 2013 Five Year Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Dec. 31, 2012 Five Year Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Mar. 31, 2013 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Dec. 31, 2012 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]
Long-term debt, gross										$ 36.1	$ 36.1	$ 35.3	$ 35.3	$ 179.6	$ 179.6	$ 179.1	$ 179.1	$ 96.3	$ 96.3	$ 100.0	$ 100.0					$ 18.3	$ 18.3	$ 18.7	$ 18.3	$ 18.3	$ 18.7	$ 425.0		$ 425.0	$ 425.0	$ 19.6	$ 19.6	$ 450.0	$ 450.0	$ 800.0	$ 800.0
Total long-term debt at subsidary	330.4	330.4
Obligation for capital lease	0.1	0.1		0.1	[1]	0.1	[1]
Total long-term debt	$ 2,025.0	$ 2,025.0		$ 332.7		$ 332.7
Debt instrument maturity year								Oct. 01, 2013	Oct. 01, 2013	Jan. 01, 2028		Jan. 01, 2028		Jan. 01, 2034		Jan. 01, 2034		Sep. 01, 2036		Sep. 01, 2036		Nov. 01, 2040		Nov. 01, 2040		Feb. 01, 2061			Feb. 01, 2061			Aug. 01, 2014				Sep. 01, 2031		Oct. 01, 2016		Oct. 01, 2021
Debt instrument interest percentage			4.20%					5.125%	5.125%	4.70%		4.70%		4.80%		4.80%		4.80%		4.80%						4.20%			4.20%		4.20%					8.125%		6.50%		7.25%
Debt instrument interest percentage minimum																						0.10%	0.04%	0.10%	0.04%							2.46%	2.22%
Debt instrument interest percentage maximum																						0.16%	0.26%	0.16%	0.26%							2.47%	2.47%

[1]

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Summary of Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 sqmi employee	Mar. 31, 2012
Service Area Square Miles	6,000
Service Area By County	24
Approximate number of retail customers	514,000
Approximate number of DPLER customers	247,000
Entity number of employees	1,475
Number of coal fired power plants	8
Employees under a collective bargaining agreement which expires in October-2011	53.00%
Capitalized interest for unregulated generation propety	$ 0.3	$ 1.4
DP&L [Member]
Service Area Square Miles	6,000
Service Area By County	24
Approximate number of retail customers	514,000
Entity number of employees	1,412
Number of coal fired power plants	8
Employees under a collective bargaining agreement which expires in October-2011	55.00%
Capitalized interest for unregulated generation propety	$ 0.3	$ 1.4

XML

Summary of Significant Accounting Policies (Summary of Property, Plant, and Equipment) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	$ 0.3	$ 1.4
DP&L [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	$ 0.3	$ 1.4

XML

Supplemental Financial Information

3 Months Ended

Mar. 31, 2013

Supplemental Financial Information [Abstract]

Supplemental Financial Information

2. Supplemental Financial Information 

Accounts receivable and Inventories are as follows at March 31, 2013 and December 31, 2012:

	At		At
	March 31,		December 31,
$ in millions	2013		2012
Accounts receivable, net:
Unbilled revenue	$	65.3	$	75.2
Customer receivables		107.5		98.2
Amounts due from partners in jointly owned plants		15.3		19.7
Coal sales		-		1.6
Other		3.1		14.6
Provision for uncollectible accounts		(1.1)		(1.1)
Total accounts receivable, net	$	190.1	$	208.2
Inventories, at average cost:
Fuel and limestone	$	72.0	$	67.3
Plant materials and supplies		40.6		41.0
Other		1.9		1.8
Total inventories, at average cost	$	114.5	$	110.1

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three months endedMarch 31, 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statement of Operations	Three months ended March 31,
$ in millions		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.1
	Total before income taxes		0.1
	Tax expense		-
	Net of income taxes		0.1
Gains and losses on cash flow hedges: (Note 9)
	Revenue		(0.5)
	Purchased power		0.8
	Total before income taxes		0.3
	Tax expense		(0.1)
	Net of income taxes		0.2
Amortization of defined benefit pension items: (Note 7)
	Reclassification to Other income / (deductions)		-
	Prior service cost for the period (1)		-
	Net loss for the period (1)		-
	Total before income taxes		-
	Tax benefit		0.3
	Net of income taxes		0.3
Total reclassifications for the period, net of income taxes		$	0.6

(1)   These Accumulated Other Comprehensive Income / (Loss) components are included in the computation of net periodic pension costs (See Note 7 for additional information).

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the three months endedMarch 31, 2013 are as follows:

$ in millions	Gains / (losses) on Available-for-sale securities		Gains / (losses) on Cash Flow Hedges		Change in Unfunded Pension Obligation		Total
Balance January 1, 2013	$	0.4	$	(2.5)	$	(1.8)	$	(3.9)
Other comprehensive income before reclassifications		0.2		1.2		-		1.4
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1		0.2		0.3		0.6
Net current period other comprehensive income		0.3		1.4		0.3		2.0
Balance March 31, 2013	$	0.7	$	(1.1)	$	(1.5)	$	(1.9)

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Summary of Significant Accounting Policies (Excise Taxes Levied by State or Local Governments) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
State/Local excise taxes	$ 13.4	$ 12.9
DP&L [Member]
State/Local excise taxes	$ 13.4	$ 12.9

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Regulatory Assets and Liabilities (Schedule of Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Total current regulatory assets	$ 18.0	$ 21.1
Total non-current regulatory assets	180.9	185.5
Total current regulatory liabilities		0.1
Total non-current regulatory liabilities	118.8	117.3
Estimated Costs of Removal - Regulated Property [Member]
Total non-current regulatory liabilities	113.6	112.1
Postretirement Benefit [Member]
Total non-current regulatory liabilities	4.8	5.0
Other Costs - Liabilities [Member]
Total current regulatory liabilities		0.1
Total non-current regulatory liabilities	0.4	0.2
DP&L [Member]
Total current regulatory assets	16.6	18.3
Total non-current regulatory assets	180.9	185.5
Total current regulatory liabilities		0.1
Total non-current regulatory liabilities	118.8	117.3
DP&L [Member] | Estimated Costs of Removal - Regulated Property [Member]
Total non-current regulatory liabilities	113.6	112.1
DP&L [Member] | Postretirement Benefit [Member]
Total non-current regulatory liabilities	4.8	5.0
DP&L [Member] | Other Costs - Liabilities [Member]
Total current regulatory liabilities		0.1
Total non-current regulatory liabilities	0.4	0.2
Deferred Recoverable Income Taxes [Member]
Type of Recovery	B/C
Amortization Through	Ongoing
Total non-current regulatory assets	34.3	35.1
Deferred Recoverable Income Taxes [Member] | DP&L [Member]
Type of Recovery	B/C
Amortization Through	Ongoing
Total non-current regulatory assets	34.3	35.1
Pension Benefits [Member]
Type of Recovery	C
Amortization Through	Ongoing
Total non-current regulatory assets	87.3	88.9
Pension Benefits [Member] | DP&L [Member]
Type of Recovery	C
Amortization Through	Ongoing
Total non-current regulatory assets	87.3	88.9
Fuel and purchased power recovery costs [Member] | DP&L [Member]
Type of Recovery	C
Amortization Through	Ongoing
Total current regulatory assets	10.0	11.3
Unamortized Loss on Reacquired Debt [Member]
Type of Recovery	C
Amortization Through	Ongoing
Total non-current regulatory assets	11.7	11.9
Unamortized Loss on Reacquired Debt [Member] | DP&L [Member]
Type of Recovery	C
Amortization Through	Ongoing
Total non-current regulatory assets	11.7	11.9
Regional Transmission Organization Costs [Member]
Type of Recovery	D
Amortization Through	2014
Total non-current regulatory assets	2.2	2.6
Regional Transmission Organization Costs [Member] | DP&L [Member]
Type of Recovery	D
Amortization Through	2014
Total non-current regulatory assets	2.2	2.6
TCRR, Transmission, Ancillary and Other PJM-related Costs [Member]
Type of Recovery	F
Amortization Through	Ongoing
Total current regulatory assets	6.6	7.0
TCRR, Transmission, Ancillary and Other PJM-related Costs [Member] | DP&L [Member]
Type of Recovery	F
Amortization Through	Ongoing
Total current regulatory assets	6.6	7.0
Deferred Storm Costs [Member]
Type of Recovery	D
Total non-current regulatory assets	24.7	24.4
Deferred Storm Costs [Member] | DP&L [Member]
Type of Recovery	D
Total non-current regulatory assets	24.7	24.4
CCEM Smart Grid and Advanced Metering Infrastructure Costs [Member]
Type of Recovery	D
Total non-current regulatory assets	6.6	6.6
CCEM Smart Grid and Advanced Metering Infrastructure Costs [Member] | DP&L [Member]
Type of Recovery	D
Total non-current regulatory assets	6.6	6.6
CCEM Energy Efficiency Program Costs [Member]
Type of Recovery	F
Amortization Through	Ongoing
Total non-current regulatory assets	3.4	5.2
CCEM Energy Efficiency Program Costs [Member] | DP&L [Member]
Type of Recovery	F
Amortization Through	Ongoing
Total non-current regulatory assets	3.4	5.2
Consumer Education Campaign
Type of Recovery	D
Total non-current regulatory assets	3.0	3.0
Consumer Education Campaign | DP&L [Member]
Type of Recovery	D
Total non-current regulatory assets	3.0	3.0
Retail Settlement System Costs [Member]
Type of Recovery	D
Total non-current regulatory assets	3.1	3.1
Retail Settlement System Costs [Member] | DP&L [Member]
Type of Recovery	D
Total non-current regulatory assets	3.1	3.1
Fuel and Purchased Power Recovery Costs [Member]
Type of Recovery	C
Amortization Through	Ongoing
Total current regulatory assets	11.4	14.1
Other Costs - Assets [Member]
Total non-current regulatory assets	4.6	4.7
Other Costs - Assets [Member] | DP&L [Member]
Total non-current regulatory assets	$ 4.6	$ 4.7

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Fair Value Measurements (Fair Value and Redemption Frequency) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Total Fair Value	$ 11.1	$ 10.6
DP&L [Member]
Total Fair Value	11.1	10.6
Equity Securities [Member]
Redemption Frequency	Immediate
Total Fair Value	5.7	5.1
Equity Securities [Member] | DP&L [Member]
Total Fair Value	5.7	5.1
Debt Securities [Member]
Redemption Frequency	Immediate
Total Fair Value	4.9	5.0
Debt Securities [Member] | DP&L [Member]
Total Fair Value	4.9	5.0
Money Market Funds [Member]
Redemption Frequency	Immediate
Total Fair Value	0.2	0.2
Money Market Funds [Member] | DP&L [Member]
Total Fair Value	0.2	0.2
Hedge Funds, Multi-strategy [Member]
Redemption Frequency	Immediate
Total Fair Value	0.3	0.3
Hedge Funds, Multi-strategy [Member] | DP&L [Member]
Total Fair Value	$ 0.3	$ 0.3

XML

Consolidated Statements of Results of Operations (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues	$ 394.6	$ 434.0
Cost of revenues:
Fuel	88.6	97.4
Purchased power	95.3	94.8
Amortization of intangibles	1.8	27.8
Total cost of revenues	185.7	220.0
Gross margin	208.9	214.0
Operating expenses:
Operation and maintenance	99.2	101.7
Depreciation and amortization	31.8	31.4
General taxes	21.0	21.7
Total operating expenses	152.0	154.8
Operating income	56.9	59.2
Other income / (expense), net:
Investment income	0.1	0.1
Interest expense	(30.5)	(29.6)
Other expense	(0.6)	(0.3)
Total other income / (expense), net	(31.0)	(29.8)
Earnings before income tax	25.9	29.4
Income tax expense	6.0	7.7
Net income	19.9	21.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Revenues	376.5	399.6
Cost of revenues:
Fuel	88.1	95.6
Purchased power	94.1	84.9
Total cost of revenues	182.2	180.5
Gross margin	194.3	219.1
Operating expenses:
Operation and maintenance	91.3	99.2
Depreciation and amortization	33.6	34.7
General taxes	19.8	20.2
Total operating expenses	144.7	154.1
Operating income	49.6	65.0
Other income / (expense), net:
Investment income	0.1	0.1
Interest expense	(9.3)	(9.6)
Other expense	(0.6)	(0.1)
Total other income / (expense), net	(9.8)	(9.6)
Earnings before income tax	39.8	55.4
Income tax expense	9.6	17.3
Net income	30.2	38.1
Dividends on preferred stock	0.2	0.2
Earnings on common stock	$ 30.0	$ 37.9

XML

Debt Obligations (Current portion - Long-term Debt) (Details) (USD $) In Millions, unless otherwise specified						3 Months Ended			3 Months Ended			3 Months Ended		3 Months Ended		3 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 01, 2011	Mar. 31, 2013 DP&L [Member]	Dec. 31, 2012 DP&L [Member]	Mar. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Mar. 31, 2012 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Dec. 31, 2012 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Mar. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Mar. 31, 2012 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Dec. 31, 2012 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Mar. 31, 2013 First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]	Dec. 31, 2012 First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]	Mar. 31, 2013 First Mortgage Bonds Maturing in October 2013 - 5.125% [Member] DP&L [Member]	Dec. 31, 2012 First Mortgage Bonds Maturing in October 2013 - 5.125% [Member] DP&L [Member]	Mar. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member]	Dec. 31, 2012 U.S. Government note maturing in February 2061 - 4.20% [Member]	Mar. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Dec. 31, 2012 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Mar. 01, 2011 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]
Obligation for capital lease	$ 0.3	$ 0.3		$ 0.3	$ 0.3
Current portion - long-term debt	580.1	584.9		570.4	570.4	100.0		100.0	100.0		100.0	479.7	484.5	470.0	470.0
Debt instrument maturity year						Nov. 01, 2040			Nov. 01, 2040			Oct. 01, 2013		Oct. 01, 2013		Feb. 01, 2061		Feb. 01, 2061
Debt instrument interest percentage			4.20%									5.125%		5.125%		4.20%		4.20%		4.20%
Debt instrument interest percentage minimum						0.10%	0.04%		0.10%	0.04%
Debt instrument interest percentage maximum						0.16%	0.26%		0.16%	0.26%
U.S. Government note maturing in February 2061 - 4.20%, current																$ 0.1	$ 0.1	$ 0.1	$ 0.1

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 251.3	$ 192.1
Restricted Cash	23.4	10.7
Accounts receivable, net (Note 2)	190.1	208.2
Inventories (Note 2)	114.5	110.1
Taxes applicable to subsequent years	52.1	69.3
Regulatory assets, current (Note 3)	18.0	21.1
Other prepayments and current assets	43.0	43.1
Total current assets	692.4	654.6
Property, plant and equipment:
Property, plant and equipment	2,625.7	2,590.4
Less: Accumulated depreciation and amortization	(134.6)	(115.9)
Property, plant and equipment, net of depreciation	2,491.1	2,474.5
Construction work in process	70.9	89.3
Total net property, plant and equipment	2,562.0	2,563.8
Other noncurrent assets:
Regulatory assets, non-current (Note 3)	180.9	185.5
Goodwill	759.1	759.1
Intangible assets, Net of amortization	50.0	50.1
Other deferred assets	29.9	34.2
Total other noncurrent assets	1,019.9	1,028.9
Total Assets	4,274.3	4,247.3
Current liabilities:
Current portion - long-term debt (Note 5)	580.1	584.9
Accounts payable	80.8	83.2
Accrued taxes	63.5	97.1
Accrued interest	55.5	31.8
Customer security deposits	14.7	15.0
Regulatory liabilities, current (Note 3)		0.1
Insurance and claims costs	12.5	11.5
Other current liabilities	86.3	96.9
Total current liabilities	893.4	920.5
Noncurrent liabilities:
Long-term debt (Note 5)	2,025.0	2,025.0
Deferred taxes (Note 6)	558.2	534.9
Taxes Payable	68.1	68.1
Regulatory liabilities, non-current (Note 3)	118.8	117.3
Pension, retiree and other benefits	63.2	61.6
Unamortized investment tax credit	3.1	3.3
Other deferred credits	71.5	71.4
Total noncurrent liabilities	2,907.9	2,881.6
Redeemable preferred stock	18.4	18.4
Common shareholders' equity:
Other paid-in capital	2,236.7	2,236.7
Accumulated other comprehensive loss	(1.9)	(3.9)
Retained deficit	(1,780.2)	(1,806.0)
Total common shareholders' equity	454.6	426.8
Total Liabilities and Shareholders' Equity	4,274.3	4,247.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
Current assets:
Cash and cash equivalents	28.3	28.5
Restricted Cash	23.4	10.7
Accounts receivable, net (Note 2)	148.2	160.0
Inventories (Note 2)	113.2	108.9
Taxes applicable to subsequent years	50.0	66.7
Regulatory assets, current (Note 3)	16.6	18.3
Other prepayments and current assets	34.9	33.0
Total current assets	414.6	426.1
Property, plant and equipment:
Property, plant and equipment	5,270.6	5,249.0
Less: Accumulated depreciation and amortization	(2,525.2)	(2,516.3)
Property, plant and equipment, net of depreciation	2,745.4	2,732.7
Construction work in process	70.4	87.8
Total net property, plant and equipment	2,815.8	2,820.5
Other noncurrent assets:
Regulatory assets, non-current (Note 3)	180.9	185.5
Intangible assets, Net of amortization	9.4	9.0
Other deferred assets	18.9	23.1
Total other noncurrent assets	209.2	217.6
Total Assets	3,439.6	3,464.2
Current liabilities:
Current portion - long-term debt (Note 5)	570.4	570.4
Accounts payable	76.7	79.1
Accrued taxes	66.9	92.2
Accrued interest	15.4	13.1
Customer security deposits	33.9	35.2
Regulatory liabilities, current (Note 3)		0.1
Other current liabilities	56.0	52.1
Total current liabilities	819.3	842.2
Noncurrent liabilities:
Long-term debt (Note 5)	332.7	332.7
Deferred taxes (Note 6)	673.3	652.0
Taxes Payable	66.0	66.0
Regulatory liabilities, non-current (Note 3)	118.8	117.3
Pension, retiree and other benefits	63.2	61.6
Unamortized investment tax credit	26.8	27.4
Other deferred credits	44.0	43.0
Total noncurrent liabilities	1,324.8	1,300.0
Redeemable preferred stock	22.9	22.9
Common shareholders' equity:
Common stock, at par value of $0.01 per share:	0.4	0.4
Other paid-in capital	803.3	803.2
Accumulated other comprehensive loss	(40.3)	(38.7)
Retained deficit	509.2	534.2
Total common shareholders' equity	1,272.6	1,299.1
Total Liabilities and Shareholders' Equity	$ 3,439.6	$ 3,464.2

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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, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Change in unrealized gain / (loss)	$ (16.5)	$ (6.6)
Derivative, Gain (Loss) on Derivative, Net	0.9	(6.6)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(15.6)	(13.2)
NYMEX Coal Contract [Member]
Change in unrealized gain / (loss)		(7.8)
Derivative, Gain (Loss) on Derivative, Net		(5.0)
Derivative Instruments, Gain (Loss) Recognized in Income, Net		(12.8)
Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)		(0.1)
Derivative, Gain (Loss) on Derivative, Net	0.5	(0.2)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	0.5	(0.3)
Commodity Contract - Heating Oil [Member]
Change in unrealized gain / (loss)		(0.1)
Derivative, Gain (Loss) on Derivative, Net		0.9
Derivative Instruments, Gain (Loss) Recognized in Income, Net		0.8
Forward Contract Power [Member]
Change in unrealized gain / (loss)	(16.5)	1.4
Derivative, Gain (Loss) on Derivative, Net	0.4	(2.3)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(16.1)	(0.9)
DP&L [Member]
Change in unrealized gain / (loss)	(10.4)	(8.0)
Derivative, Gain (Loss) on Derivative, Net	1.2	(4.3)
Gain (Loss) on Derivative Instruments, Net, Pretax	(9.2)	(12.3)
Partner's share of gain (loss)		(3.5)
Regulatory (asset)/liability		(1.0)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(9.2)	(12.3)
DP&L [Member] | NYMEX Coal Contract [Member]
Change in unrealized gain / (loss)		(7.8)
Derivative, Gain (Loss) on Derivative, Net		(5.0)
Gain (Loss) on Derivative Instruments, Net, Pretax		(12.8)
Partner's share of gain (loss)		(3.5)
Regulatory (asset)/liability		(1.1)
Derivative Instruments, Gain (Loss) Recognized in Income, Net		(12.8)
DP&L [Member] | Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)		(0.1)
Derivative, Gain (Loss) on Derivative, Net	0.5	(0.2)
Gain (Loss) on Derivative Instruments, Net, Pretax	0.5	(0.3)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	0.5	(0.3)
DP&L [Member] | Commodity Contract - Heating Oil [Member]
Change in unrealized gain / (loss)		(0.1)
Derivative, Gain (Loss) on Derivative, Net		0.9
Gain (Loss) on Derivative Instruments, Net, Pretax		0.8
Regulatory (asset)/liability		0.1
Derivative Instruments, Gain (Loss) Recognized in Income, Net		0.8
DP&L [Member] | Forward Contract Power [Member]
Change in unrealized gain / (loss)	(10.4)
Derivative, Gain (Loss) on Derivative, Net	0.7
Gain (Loss) on Derivative Instruments, Net, Pretax	(9.7)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(9.7)
Revenue [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		3.4
Revenue [Member] | Forward Contract Power [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		3.4
Revenue [Member] | DP&L [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(1.1)	1.6
Revenue [Member] | DP&L [Member] | Forward Contract Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(1.1)	1.6
Fuel [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		(7.6)
Fuel [Member] | NYMEX Coal Contract [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		(8.2)
Fuel [Member] | Commodity Contract - Heating Oil [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		0.6
Fuel [Member] | DP&L [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		(7.6)
Fuel [Member] | DP&L [Member] | NYMEX Coal Contract [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		(8.2)
Fuel [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		0.6
O&M [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		0.1
O&M [Member] | Commodity Contract - Heating Oil [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax		0.1
O&M [Member] | DP&L [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		0.1
O&M [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		0.1
Purchased Power [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax	(15.6)	(4.6)
Purchased Power [Member] | Commodity Contract - FTR [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax	0.5	(0.3)
Purchased Power [Member] | Forward Contract Power [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax	(16.1)	(4.3)
Purchased Power [Member] | DP&L [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(8.1)	(1.9)
Purchased Power [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	0.5	(0.3)
Purchased Power [Member] | DP&L [Member] | Forward Contract Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(8.6)	(1.6)
Partners Share of Gain Loss [Member]
Partner's share of gain (loss)		(3.5)
Partners Share of Gain Loss [Member] | NYMEX Coal Contract [Member]
Partner's share of gain (loss)		(3.5)
Regulatory Asset Liability [Member]
Regulatory (asset)/liability		(1.0)
Regulatory Asset Liability [Member] | NYMEX Coal Contract [Member]
Regulatory (asset)/liability		(1.1)
Regulatory Asset Liability [Member] | Commodity Contract - Heating Oil [Member]
Regulatory (asset)/liability		$ 0.1

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Summary of Significant Accounting Policies (Sale of Receivables) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
ComEd [Member]
Proceeds from Sale of Other Receivables	$ 16.9	$ 0
Duke Energy [Member]
Proceeds from Sale of Other Receivables	$ 4.5	$ 2.0

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Business Segments (Segment Financial Information) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Total revenues	$ 394.6	$ 434.0
Fuel Costs	88.6	97.4
Purchased power	95.3	94.8
Amortization of intangibles	1.8	27.8
Gross margin	208.9	214.0
Depreciation and amortization	31.8	31.4
Interest expense	30.5	29.6
Income tax expense (benefit)	6.0	7.7
Net income (loss)	19.9	21.7
Total Assets	4,274.3		4,247.3
Utility [Member]
Revenues from external customers	271.8	312.8
Intersegment revenues	104.7	86.8
Total revenues	376.5	399.6
Fuel Costs	88.1	95.6
Purchased power	94.1	84.9
Gross margin	194.3	219.1
Depreciation and amortization	33.6	34.7
Interest expense	9.3	9.6
Income tax expense (benefit)	9.6	17.3
Net income (loss)	30.2	38.1
Total Assets	3,439.6	3,464.2
Capital expenditures	33.6	53.2
Competitive Retail [Member]
Revenues from external customers	117.3	112.1
Total revenues	117.3	112.1
Purchased power	105.7	96.7
Gross margin	11.6	15.4
Depreciation and amortization	0.1	0.2
Interest expense	0.2	0.2
Income tax expense (benefit)	0.9	3.4
Net income (loss)	1.6	6.0
Total Assets	95.8	99.2
Capital expenditures		0.4
Other Reportable Business Segment [Member]
Revenues from external customers	5.5	9.1
Intersegment revenues	0.9	0.9
Total revenues	6.4	10.0
Fuel Costs	0.5	1.8
Purchased power	0.2
Amortization of intangibles	1.8	27.8
Gross margin	3.9	(19.6)
Depreciation and amortization	(1.9)	(3.5)
Interest expense	21.2	20.0
Income tax expense (benefit)	(4.5)	(13.0)
Net income (loss)	(11.9)	(22.4)
Total Assets	738.9	683.9
Capital expenditures	0.2	0.4
Adjustments and Eliminations [Member]
Intersegment revenues	(105.6)	(87.7)
Total revenues	(105.6)	(87.7)
Purchased power	(104.7)	(86.8)
Gross margin	(0.9)	(0.9)
Interest expense	(0.2)	(0.2)
Parent Company [Member]
Revenues from external customers	394.6	434.0
Total revenues	394.6	434.0
Fuel Costs	88.6	97.4
Purchased power	95.3	94.8
Amortization of intangibles	1.8	27.8
Gross margin	208.9	214.0
Depreciation and amortization	31.8	31.4
Interest expense	30.5	29.6
Income tax expense (benefit)	6.0	7.7
Net income (loss)	19.9	21.7
Total Assets	4,274.3	4,247.3
Capital expenditures	$ 33.8	$ 54.0

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2013

Regulatory Assets and Liabilities

$ in millions	Type of Recovery (a)	Amortization through	At March 31, 2013		At December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	6.6	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		11.4		14.1
Total regulatory assets, current			$	18.0	$	21.1
Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	34.3	$	35.1
Pension benefits	C	Ongoing		87.3		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.7		11.9
Regional transmission organization costs	D	2014		2.2		2.6
Deferred storm costs	D			24.7		24.4
CCEM smart grid and advanced metering infrastructure costs	D			6.6		6.6
CCEM energy efficiency program costs	F	Ongoing		3.4		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.6		4.7
Total regulatory assets, non-current			$	180.9	$	185.5
Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.6	$	112.1
Postretirement benefits				4.8		5.0
Other				0.4		0.2
Total regulatory liabilities, non-current			$	118.8	$	117.3

DP&L [Member]

Regulatory Assets and Liabilities

$ in millions	Type of Recovery (a)	Amortization through	At March 31, 2013		At December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	6.6	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		10.0		11.3
Total regulatory assets, current			$	16.6	$	18.3
Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	34.3	$	35.1
Pension benefits	C	Ongoing		87.3		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.7		11.9
Regional transmission organization costs	D	2014		2.2		2.6
Deferred storm costs	D			24.7		24.4
CCEM smart grid and advanced metering infrastructure costs	D			6.6		6.6
CCEM energy efficiency program costs	F	Ongoing		3.4		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.6		4.7
Total regulatory assets, non-current			$	180.9	$	185.5
Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1
Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.6	$	112.1
Postretirement benefits				4.8		5.0
Other				0.4		0.2
Total regulatory liabilities, non-current			$	118.8	$	117.3

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Summary of Signficant Accounting Policies (Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Excise Taxes Collected	$ 13.4	$ 12.9
DP&L [Member]
Excise Taxes Collected	$ 13.4	$ 12.9

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Debt Obligations (Tables)

3 Months Ended

Mar. 31, 2013

Long-term Debt

$ in millions	March 31, 2013		December 31, 2012
Pollution control series maturing in January 2028 - 4.7%	$	36.1	$	36.1
Pollution control series maturing in January 2034 - 4.8%		179.6		179.6
Pollution control series maturing in September 2036 - 4.8%		96.3		96.3
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligations		0.1		0.1
Total long-term debt at subsidiary		330.4		330.4
Bank term loan-maturing in August 2014 - variable rates: 2.46% - 2.47% and 2.22% - 2.47% (a)		425.0		425.0
Senior unsecured bonds maturing October 2016 - 6.5%		450.0		450.0
Senior unsecured bonds maturing October 2021 - 7.3%		800.0		800.0
Note to DPL Capital Trust II maturing in September 2031 - 8.125%		19.6		19.6
Total non-current portion - long-term debt - DPL	$	2,025.0	$	2,025.0

Current Portion - Long-term Debt

$ in millions	March 31, 2013		December 31, 2012
First mortgage bonds maturing in October 2013 - 5.125%	$	479.7	$	484.5
Pollution control series maturing in November 2040 - variable rates: 0.10% - 0.16% and 0.04% - 0.26% (a)		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.3		0.3
Total current portion - long-term debt - DPL	$	580.1	$	584.9

Long-term Debt Maturities

$ in millions
Due within one year	$	570.4
Due within two years		425.2
Due within three years		0.1
Due within four years		450.1
Due within five years		0.2
Thereafter		1,152.8
Total maturities		2,598.8
Unamortized premiums and discounts		6.3
Total long-term debt	$	2,605.1

DP&L [Member]

Long-term Debt

$ in millions	March 31, 2013		December 31, 2012
Pollution control series maturing in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series maturing in January 2034 - 4.8%		179.1		179.1
Pollution control series maturing in September 2036 - 4.8%		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligation		0.1		0.1
Unamortized debt discount		(0.1)		(0.1)
Total non-current portion - long-term debt - DP&L	$	332.7	$	332.7

Current Portion - Long-term Debt

$ in millions	March 31, 2013		December 31, 2012
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0	$	470.0
Pollution control series maturing in November 2040 - variable rates: 0.10% - 0.16% and 0.04% - 0.26% (a)		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.3		0.3
Total current portion - long-term debt - DP&L	$	570.4	$	570.4

Long-term Debt Maturities

$ in millions
Due within one year	$	570.4
Due within two years		0.2
Due within three years		0.1
Due within four years		0.1
Due within five years		0.1
Thereafter		332.3
Total maturities		903.2
Unamortized discounts		(0.1)
Total long-term debt	$	903.1

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Overview and Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Overview and Summary of Significant Accounting Policies

DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1.  Overview and Summary of Significant Accounting Policies

Description of Business  

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio.  DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared.  Refer to Note 11 for more information relating to these reportable segments.  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.   

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

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers.  DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011.  DPLER has approximately 247,000 customers currently located throughout Ohio and Illinois.  DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations.  DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves. 

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

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

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

DPL and its subsidiaries employed 1,475 people as of March 31, 2013, of which 1,412 employees were employed by DP&L.  Approximately 53% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014. 

Financial Statement Presentation  

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP.  DP&L’s undivided ownership interests in certain coal-fired generating facilities and numerous transmission facilities are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date for DPL.  Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statement of Operations.  See Note 4 for more information. 

All material intercompany accounts and transactions are eliminated in consolidation.   

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X.  Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report.  Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.   

In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2013; our results of operations for the three months ended March 31, 2013 and 2012 and our cash flows for the three months ended March 31, 2013 and 2012.  Unless otherwise noted, all adjustments are normal and recurring in nature.  Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013. 

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

Goodwill Impairment

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

Sale of Receivables 

In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy.  These sales are at face value for cash at the amounts billed for DPLER customers’ use of energy.  Total receivables sold to Duke Energy during the three months endedMarch 31, 2013 and 2012 were $4.5 million and  $2.0 million, respectively.  Similarly, MC Squared sells receivables from their customers in ComEd territory to ComEd.  Total receivables sold to ComEd during the three months endedMarch 31, 2013 and 2012 were $16.9 million and $0.0million, respectively.  There is no recourse or any other continuing involvement associated with the sold receivables.

Property, Plant and Equipment  

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment.  Property, plant and equipment are stated at cost.  For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC).  AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects.  For non-regulated property including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. 

Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.  The total AFUDC and capitalized interest was $0.3 million and $1.4 million during the three months endedMarch 31, 2013 and 2012, respectively.  

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

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

Intangibles 

Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP.  Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances.  In addition, we recorded emission allowances at their fair value as of the Merger date.  Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.  During the three months ended March 31, 2013 and 2012,  DPL had no gains from the sale of emission allowances.   

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

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities 

DPL collects certain excise taxes levied by state or local governments from its customers.  These taxes are accounted for on a net basis and recorded as a reduction in revenues.  The amounts for the three months endedMarch 31, 2013 and 2012 were $13.4 million and $12.9 million, respectively. 

Recently Issued Accounting Standards 

Offsetting Assets and Liabilities

The FASB recently issued ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”to limit the scope of ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” to derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions.  This ASU is effective for annual and interim periods beginning on or after January 1, 2013.  The FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220):  Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards  

Offsetting Assets and Liabilities 

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

Testing Indefinite-Lived Intangible Assets for Impairments 

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012.  We adopted this ASU on January 1, 2013.  This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.”  ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30.  This rule did not have a material effect on our overall results of operations, financial position or cash flows.

DP&L [Member]

Overview and Summary of Significant Accounting Policies

The Dayton Power and Light Company

Notes to Condensed Financial Statements (Unaudited)

1.  Overview and Summary of Significant Accounting Policies 

Description of Business  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.  DP&L is a wholly owned subsidiary of DPL. 

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

DP&L’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. 

DP&L employed 1,412 people as of March 31, 2013.  Approximately 55% of all employees are under a collective bargaining agreement which expires on October 31, 2014. 

Financial Statement Presentation  

DP&L does not have any subsidiaries.  DP&L has undivided ownership interests in seven electric generating facilities and numerous transmission facilities which are included in the financial statements at amortized cost.  Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statement of Operations.  See Note 4 for more information.   

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X.  Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report.  Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.   

In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2013; our results of operations for the three months ended March 31, 2013 and 2012 and our cash flows for the three months ended March 31, 2013 and 2012.  Unless otherwise noted, all adjustments are normal and recurring in nature.  Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013. 

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.  For non-regulated property including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. 

Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.  The total of AFUDC and capitalized interest was $0.3 million and $1.4 million for the three months endedMarch 31, 2013 and 2012, respectively. 

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

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

Intangibles 

Intangibles consist of emission allowances and renewable energy credits.  Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances.  Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.  Emission allowances are amortized as they are used in our operations.  Renewable energy credits are amortized as they are used or retired.  During the three months ended March 31, 2013 and 2012,  DP&L had no gains from the sale of emission allowances.

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.  These taxes are accounted for on a net basis and are recorded as a reduction in revenues.  The amounts for the three months endedMarch 31, 2013 and 2012 were $13.4 million and $12.9 million, respectively.

Related Party Transactions 

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

	Three months ended
	March 31,
	2013		2012
DP&L Revenues:
Sales to DPLER (a)	$	78.7	$	83.0
Sales to MC Squared	$	25.6	$	-
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.6)
Expense recoveries for services provided to DPLER (c)	$	1.1	$	0.9
DP&L Customer security deposits:
Deposits received from DPLER (d)	$	19.2	$	-

(a)DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers.  The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The decrease in DP&L’s sales to DPLER during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, is primarily due to the transfer price for the current customer base being lower than the previous year’s transfer price.  The increase in DP&L’s sales to MC Squared during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, is a result of these sales beginning in September 2012. 

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

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

(d)DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity.  Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.

Recently Issued Accounting Standards 

Offsetting Assets and Liabilities

The FASB recently issued ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”to limit the scope of ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” to derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions.  This ASU became effective for annual and interim periods beginning on or after January 1, 2013.  The FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220):  Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards  

XML

Consolidated Statements of Comprehensive Income/(Loss) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net income	$ 19.9	$ 21.7
Available-for-sale securities activity:
Change in fair value of available-for-sale securities	0.2	0.4
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.1
Total change in fair value of available-for-sale securities	0.3	0.4
Derivative activity:
Change in derivative fair value	1.2	7.6
Reclassification of earnings of Cash Flow Hedge	0.2	(0.9)
Total change in fair value of derivatives	1.4	6.7
Pension and postretirement activity:
Reclassification to earnings of Pension	0.3
Total change in unfunded pension obligation	0.3
Other comprehensive income / (loss)	2.0	7.1
Net comprehensive income / (loss)	21.9	28.8
THE DAYTON POWER AND LIGHT COMPANY [Member]
Net income	30.2	38.1
Available-for-sale securities activity:
Change in fair value of available-for-sale securities	0.2	0.4
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.1
Total change in fair value of available-for-sale securities	0.3	0.4
Derivative activity:
Change in derivative fair value	(2.6)	(1.5)
Reclassification of earnings of Cash Flow Hedge	(0.2)	(1.7)
Total change in fair value of derivatives	(2.8)	(3.2)
Pension and postretirement activity:
Prior service cost for the period	0.9
Reclassification to earnings of Pension		1.1
Total change in unfunded pension obligation	0.9	1.1
Other comprehensive income / (loss)	(1.6)	(1.7)
Net comprehensive income / (loss)	$ 28.6	$ 36.4

XML

Commitments, Enviromental, Legal

3 Months Ended

Mar. 31, 2013

Contractual Obligations, Commercial Commitments And Contingencies

10.  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 DPLER’s wholly owned subsidiary, MC Squared, providing financial or performance assurance to third parties.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis,thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.

At March 31, 2013,  DPL  had $18.0 million of guarantees to third parties for future financial or performance assurance under such agreements, including $17.7 million of guarantees on behalf of DPLE and DPLER and $0.3 million of guarantees on behalf of MC Squared.  The guarantee arrangements entered into by DPL with these third parties cover select present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable by DPL upon written notice within a certain time to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.8 million at March 31, 2013.   

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 DPLwould 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. 

Equity Ownership Interest  

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP.  As of March 31, 2013,  DP&L could be responsible for the repayment of 4.9%, or $77.9 million, of a $1,588.8 million debt obligation that features maturities from 2018 to 2040.  This would only happen if this electric generation company defaulted on its debt payments.  As of March 31, 2013, we have no knowledge of such a default. 

Commercial Commitments and Contractual Obligations 

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2012.

Contingencies 

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations.  We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies.  However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2013, cannot be reasonably determined. 

Environmental Matters

DPL’s,  DP&L’s 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 environmental losses that are probable of occurring and can be reasonably estimated.  At March 31, 2013, we have reserves of approximately $3.1 million for environmental matters.  We evaluate the potential liability related to probable losses arising from environmental matters quarterly and may revise our estimates.  Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial position or cash flows.

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

On July 15, 2011, Duke Energy, a co-owner at Beckjord Unit 6, 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 commonly owned Unit 6, in December 2014.  This was followed by a notification by the joint owners of Beckjord 6 to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit.  We do not believe that any additional accruals are needed as a result of this decision. 

DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated June 1, 2013.  In addition, DP&L has notified PJM that the remaining Hutchings units will be deactivated June 1, 2015.  We do not believe that any additional accruals are needed related to the Hutchings Station. 

Environmental Matters Related to Air Quality

Clean Air Act Compliance

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

Cross-State Air Pollution Rule 

The USEPA promulgated CAIR on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing electric generating stations located in 27 eastern states, including Ohio, and the District of Columbia.  CAIR contemplated two implementation phases.  The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively.  A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015.  To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs.  CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA. 

In response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” in these 27 States,  which is now referred to as CSAPR.  Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources in these 27 states, such as power stations.  Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels.  Many states, utilities and other affected parties filed petitions for review, challenging CSAPR before the U.S. Court of Appeals for the District of Columbia.  A large subset of the petitioners also sought a stay of CSAPR. On December 30, 2011, the D.C. Circuit granted a stay of CSAPR and directed the USEPA to continue administering CAIR. On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that the USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance.  As a result of this ruling, the surviving provisions of CAIR will continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes.  Assuming that the USEPA promulgates a replacement interstate transport rule addressing the D.C. Circuit Court’s ruling, we believe companies will have three years from the date of promulgation before they would be required to comply.  At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial position, results of operations or cash flows. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated.  On January 24, 2013, the D.C. Circuit Court denied this petition for rehearing.  Therefore, CAIR currently remains in effect.  On March 19, 2013, the USEPA and several environmental groups filed two petitions for review of the D.C. Circuit Court’s decision with the U.S. Supreme Court.  If CSAPR were to be reinstated in its current form, we would not expect any material capital costs for DP&L’s units or stations, assuming Beckjord Unit 6 and Hutchings Station will not operate on coal in 2015 due to implementation of MATS.  Because we cannot predict the final outcome of any replacement interstate transport rulemaking, we cannot predict its financial impact on DP&L’s operations. 

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired EGUs.  The standards include new requirements for emissions of mercury and a number of other heavy metals.  The USEPA Administrator signed the final rule, now called MATS, on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012.  An additional portion of MATS imposing emissions limits on and requiring pollution control technology at new coal and oil-fueled power plants was finalized on March 28, 2013.  Our affected EGUs will have to come into compliance with MATS by April 16, 2015.  DP&L is evaluating the costs that may be incurred to comply with MATS; however, MATS could have a material adverse effect on our operations and result in material compliance costs. 

On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities.  The final rule was published in the Federal Register on March 21, 2011.  This rule affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities.  The regulations contain emissions limitations, operating limitations and other requirements.  In December 2011, the USEPA proposed additional changes to this rule.  On December 21, 2012, the Administrator of the USEPA signed the final rule and it was published in the Federal Register on January 31, 2013.  Compliance costs are currently 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 December 31, 2012, the USEPA redesignated Adams County, where Stuart and Killen are located, to attainment status.  This status may be temporary, as on December 12, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter.  This will begin a process of redesignations during 2014.  We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial position or results of operations.

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 revisions to the ozone standard, if any, on its operations.  The USEPA is required to review the ozone standard in 2013 and is likely to propose a more stringent standard.

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. 

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.  Numerous units owned and operated by us will be affected by BART.  We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions 

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO₂ emissions from motor vehicles, the USEPA made a finding that CO₂ and certain other GHGs are pollutants under the CAA.  Subsequently, under the CAA, the USEPA determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change.  This finding became effective in January 2010.  On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule.  Under the USEPA’s view, this is the final action that renders CO₂ and other GHGs “regulated air pollutants” under the CAA. 

Under the USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011.  The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs.  Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time.  The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis.  Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule.  We cannot predict the outcome of this petition.  The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material. 

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

Approximately 97% of the energy we produce is generated by coal.  DP&L’s share of CO₂  emissions at generating units and stations we own and co-own is approximately 14 million tons annually.  Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial position.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.   

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

Litigation Involving Co-Owned Stations

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system.  Although we were not named as a party to these lawsuits, DP&L is a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L.  Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law. 

As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the Stuart Station are subject to certain specified emission targets related to NO_x, 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 position or cash flows in the future.

Notices of Violation Involving Co-Owned Stations

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 Ohio Power (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 stations.

In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart Station (co-owned by DP&L, Duke Energy and Ohio Power) for alleged violations of the CAA.  The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest, including the NOVs noted in the paragraph above.  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.

On March 13, 2008, Duke Energy, the operator of the Zimmer Station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and air permits for the station in areas including SO₂, opacity and increased heat input. A second NOV and FOV with similar allegations werereceived by Duke Energy on November 4, 2010.  Also in 2010, the USEPA issued an NOV to Zimmer for excess emissions.  DP&L is a co-owner of the Zimmer Station and could be affected by the eventual resolution of these matters.  Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters.  DP&L is unable to predict the outcome of these matters.

Notices of Violation Involving Wholly Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station.  The NOVs alleged deficiencies relate to stack opacity and particulate emissions.  Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA.  On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6.  DP&L does not believe that the projects described in the November 2009 NOV were modifications subject to NSR.  DP&L is engaged in discussions with the USEPA and Justice Department to resolve each of these matters, but DP&L is unable to determine the timing, costs or method by which these matters may be resolved.  The Ohio EPA is kept apprised of these discussions.

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

Clean Water Act – Regulation of Water Intake

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures.  The rules required an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  A number of parties appealed the rules.  In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available.  The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011.  We submitted comments to the proposed regulations on August 17, 2011.  In July 2012, the USEPA announced that the final rules will be released in June 2013.  We do not yet know the impact these proposed rules, when finalized, will have on our operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, we submitted an application for the renewal of the Stuart Station NPDES permit that was due to expire on June 30, 2007.  In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River.  On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term.  Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options.  The Ohio EPA issued a revised draft permit that was received on November 12, 2008.  In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit.  In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA.  In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation.  In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011.  We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011.  In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA.  This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA.  The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012.  The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system.  DP&L submitted comments to the draft permit.  In November 2012, Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments.  In December 2012, the USEPA formally withdrew their objection to the permit.  On January 7, 2013, Ohio EPA issued a final permit.  On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission.  Depending on the outcome of the appeals process, the effects could be material on DP&L’s operations.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities.  The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities.  On April 19, 2013,  the USEPA announced a proposed new rule regulating discharge of pollutants from various waste streams associated with steam EGUs.  A 60 day comment period will be triggered once the proposal is published in the Federal Register.  At present, DP&L is reviewing the proposed rule and is currently unable to predict the impact this rulemaking will have on its operations.

In August 2012, DP&L submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013.  At present, the outcome of this proceeding is not known. 

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station.  The NOV indicated that construction activities caused sediment to flow into downstream creeks.  In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill.  DP&L has installed sedimentation ponds as part of the runoff control measures to address this issue and is working with the various agencies to resolve their concerns including entering into settlement discussions with the USEPA, although they have not issued any formal NOV.  On March 28, 2013, DP&L received a proposed Administrative Order from the USEPA which is currently under review by DP&L management.  This proposed order may affect the landfill’s construction schedule and delay its operational date.  DP&L has accrued an immaterial amount for anticipated penalties related to this issue.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site.  DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010.  On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site.  On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill.  Discovery, including depositions of past and present DP&L employees, was conducted in 2012.  On February 8, 2013, the Court granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by PRP group in their performing a Remediation Investigation and Feasibility Study.  That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending.  DP&L is unable to predict the outcome of the appeal.  Additionally, the Court’s ruling does not address future litigation that may arise with respect to actual remediation costs.  While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site.  In October 2012, DP&L received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on DP&L’s service center property.  After informal discussions with the USEPA, DP&L complied with this sampling request and the sampling was conducted in February 2013.  On February 28, 2013, the plaintiff’s group referenced above entered into an Administrative Settlement Agreement Consent Order (ASACO) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), percholorethylene (PCE), and methane.  On April 16, 2013, the plaintiff’s group filed a new complaint against DP&L and approximately 25 other defendants alleging that they share liability for these costs.  DP&L will oppose the allegations that it bears any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint.

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site.  Information available to DP&L does not demonstrate that it contributed hazardous substances to the site.  While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs).  While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L.  While the USEPA had indicated that the official release date for a proposed rule would be sometime in April 2013, it will likely be delayed until late 2013 or early 2014.  At present, DP&L is unable to predict the impact this initiative will have on its operations.

Regulation of Ash Ponds

In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and Stuart Stations.  Subsequently, the USEPA collected similar information for the Hutchings Station. 

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

In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds.  In May 2012, we received a draft report on the inspection.  DP&L submitted comments on the draft report in June 2012.  On March 14, 2013,DP&L received the final report on the inspection of the Killen Station ash pond inspection from the USEPA which included recommended actions.  DP&L is reviewing the final report and will submit a response to the USEPA.  There were no material compliance requirements included in the report.

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.  Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed.  At present, the timing for a final rule regulating coal combustion byproducts cannot be determined, but the USEPA has stated possibly by 2014.  If coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on its operations.

Notice of Violation Involving Co-Owned Units

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

Legal and Other Matters

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

DP&L [Member]

Contractual Obligations, Commercial Commitments And Contingencies

11.  Contractual Obligations, Commercial Commitments and Contingencies

DP&L – Equity Ownership Interest  

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP.  As of March 31, 2013,  DP&L could be responsible for the repayment of 4.9%, or $77.9 million, of a $1,588.8 million debt obligation that features maturities from 2018 to 2040.  This would only happen if this electric generation company defaulted on its debt payments.  As of March 31, 2013, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2012.

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our Condensed Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies.  However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Financial Statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2013, cannot be reasonably determined.

Environmental Matters

DP&L’s 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 environmental losses that are probable of occurring and can be reasonably estimated.  At March 31, 2013, we have reserves of approximately$3.1million for environmental matters.  We evaluate the potential liability related to probable losses arising from environmental matters quarterly and may revise our estimates.  Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial position or cash flows.

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

On July 15, 2011, Duke Energy, a co-owner at Beckjord Unit 6, 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 commonly owned Unit 6, in December 2014.  This was followed by a notification by the joint owners of Beckjord Unit 6 to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit.  We are depreciating Beckjord Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision. 

DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated June 1, 2013.  In addition, DP&L has notified PJM that the remaining Hutchings units will be deactivated June 1, 2015.  We do not believe that any additional accruals are needed related to the Hutchings Station. 

Environmental Matters Related to Air Quality

Clean Air Act Compliance

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

Cross-State Air Pollution Rule 

The USEPA promulgated the Clean Air Interstate Rule (CAIR) on March 10, 2005, which required allowance surrender for SO₂ and NO_x emissions from existing electric generating stations located in 27 eastern states, including Ohio, and the District of Columbia.  CAIR contemplated two implementation phases.  The first phase was to begin in 2009 and 2010 for NO_x and SO₂, respectively.  A second phase with additional allowance surrender obligations for both air emissions was to begin in 2015.  To implement the required emission reductions for this rule, the states were to establish emission allowance based “cap-and-trade” programs.  CAIR was subsequently challenged in federal court, and on July 11, 2008, the United States Court of Appeals for the D.C. Circuit issued an opinion striking down much of CAIR and remanding it to the USEPA.

In response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” in these 27 States,  which is now referred to as the Cross-State Air Pollution Rule (CSAPR).  Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources in these 27 states, such as power stations.  Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of73% and additional NO_x reductions of 54%  from 2005 levels.  Many states, utilities and other affected parties filed petitions for review, challenging CSAPR before the U.S. Court of Appeals for the District of Columbia.  A large subset of the petitioners also sought a stay of CSAPR. On December 30, 2011, the D.C. Circuit granted a stay of CSAPR and directed the USEPA to continue administering CAIR. On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance.  As a result of this ruling, the surviving provisions of CAIR will continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes.  Assuming that the USEPA promulgates a replacement interstate transport rule addressing the D.C. Circuit Court’s ruling, we believe companies will have three years from the date of promulgation before they would be required to comply.  At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial position, results of operations or cash flows. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated.  On January 24, 2013, the D.C. Circuit Court denied this petition for rehearing.  Therefore, CAIR currently remains in effect.  On March 19, 2013, the USEPA and several environmental groups filed two petitions for review of the D.C. Circuit Court’s decision with the U.S. Supreme Court.  If CSAPR were to be reinstated in its current form, we would not expect any material capital costs for DP&L’s units or stations, assuming Beckjord Unit 6 and Hutchings Station will not operate on coal in 2015 due to implementation of the MATS.  Because we cannot predict the final outcome of any replacement interstate transport rulemaking, we cannot predict its financial impact on DP&L’s operations. 

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired EGUs.  The standards include new requirements for emissions of mercury and a number of other heavy metals.  The USEPA Administrator signed the final rule, now called MATS, on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012.  An additional portion of MATS imposing emissions limits on and requiring pollution control technology at new coal and oil-fueled power plants was finalized on March 28, 2013.  Our affected EGUs will have to come into compliance with MATS by April 16, 2015.  DP&L is evaluating the costs that may be incurred to comply with MATS; however, MATS could have a material adverse effect on our operations and result in material compliance costs. 

On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities.  The final rule was published in the Federal Register on March 21, 2011.  This rule affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities.  The regulations contain emissions limitations, operating limitations and other requirements.  In December 2011, the USEPA proposed additional changes to this rule.  On December 21, 2012, the Administrator of the USEPA signed the final rule and it was published in the Federal Register on January 31, 2013.  Compliance costs are currently 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 December 31, 2012, the USEPA redesignated Adams County, where Stuart and Killen are located, to attainment status.  This status may be temporary, as on December 12, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter.  This will begin a process of redesignations during 2014.  We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial position or results of operations.

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 revisions to the ozone standard, if any, on its operations.  The USEPA is required to review the ozone standard in 2013 and is likely to propose a more stringent standard.

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. 

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.  Numerous units owned and operated by us will be affected by BART.  We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions 

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO₂ emissions from motor vehicles, the USEPA made a finding that CO₂ and certain other GHGs are pollutants under the CAA.  Subsequently, under the CAA, the USEPA determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change.  This finding became effective in January 2010.  On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule.  Under the USEPA’s view, this is the final action that renders CO₂ and other GHGs “regulated air pollutants” under the CAA. 

Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011.  The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs.  Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time.  The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis.  Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule.  We cannot predict the outcome of this petition.  The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material. 

On April 13, 2012, the USEPA published its proposed GHG standards for new EGUsunder CAA subsection 111(b), which would require certain new EGUs to meet a standard of1,000 pounds of CO₂ per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation.  The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive CO₂ emission control technology to meet the standard.  Furthermore, the USEPA may propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d).  These latter rules may focus on energy efficiency improvements at electric generating stations.  We cannot predict the effect of these standards, if any, on DP&L’s operations.

Approximately 97% 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 14 million tons annually.  Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial position.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.   

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

Litigation Involving Co-Owned Units

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system.  Although we were not named as a party to these lawsuits, DP&L is a co-owner of coal-fired stations with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L.  Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law. 

As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the Stuart Station are subject to certain specified emission targets related to NO_x, 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 position or cash flows in the future.

Notices of Violation Involving Co-Owned Units

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 Ohio Power (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 units.

In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart Station (co-owned by DP&L, Duke Energy and Ohio Power) for alleged violations of the CAA.  The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest, including the NOVs noted in the paragraph above.  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.

On March 13, 2008, Duke Energy, the operator of the Zimmer Station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and air permits for the station in areas including SO₂, opacity and increased heat input. A second NOV and FOV with similar allegations was received by Duke Energy on November 4, 2010.  Also in 2010, the USEPA issued an NOV to Zimmer for excess emissions.  DP&L is a co-owner of the Zimmer Station and could be affected by the eventual resolution of these matters.  Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters.  DP&L is unable to predict the outcome of these matters.

Notices of Violation Involving Wholly Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station.  The NOVs alleged deficiencies relate to stack opacity and particulate emissions.  Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA.  On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6.  DP&L does not believe that the projects described in the November 2009 NOV were modifications subject to NSR.  DP&L is engaged in discussions with the USEPA and Justice Department to resolve each of these matters, but DP&L is unable to determine the timing, costs or method by which these matters may be resolved.  The Ohio EPA is kept apprised of these discussions.

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

Clean Water Act – Regulation of Water Intake

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures.  The rules required an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  A number of parties appealed the rules.  In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available.  The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011.  We submitted comments to the proposed regulations on August 17, 2011.  In July 2012, the USEPA announced that the final rules will be released in June 2013.  We do not yet know the impact these proposed rules, when finalized, will have on our operations.

Clean Water Act – Regulation of Water Discharge

In December 2006, we submitted an application for the renewal of the Stuart Station NPDES permit that was due to expire on June 30, 2007.  In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River.  On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term.  Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options.  The Ohio EPA issued a revised draft permit that was received on November 12, 2008.  In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit.  In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA.  In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation.  In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011.  We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011.  In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA.  This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA.  The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012.  The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system.  DP&L submitted comments to the draft permit.  In November 2012, Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments.  In December 2012, the USEPA formally withdrew their objection to the permit.  On January 7, 2013, Ohio EPA issued a final permit.  On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission.  Depending on the outcome of the appeals process, the effects could be material on DP&L’s operations.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities.  The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities.  On April 19, 2013,  the USEPA announced a proposed new rule regulating discharge of pollutants from various waste streams associated with steam EGUs.  A 60 day comment period will be triggered once the proposal is published in the Federal Register.  At present, DP&L is reviewing the proposed rule and is currently unable to predict the impact this rulemaking will have on its operations.

In August 2012, DP&L submitted an application for the renewal of the Killen Station NPDES permit which expired in January 2013.  At present, the outcome of this proceeding is not known. 

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the Stuart Station.  The NOV indicated that construction activities caused sediment to flow into downstream creeks.  In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill.  DP&L has installed sedimentation ponds as part of the runoff control measures to address this issue and is working with the various agencies to resolve their concerns including entering into settlement discussions with the USEPA, although they have not issued any formal NOV.  On March 28, 2013, DP&L received a proposed Administrative Order from the USEPA which is currently under review by DP&L management.  This proposed order may affect the landfill’s construction schedule and delay its operational date.  DP&L has accrued an immaterial amount for anticipated penalties related to this issue.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site.  DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010.  On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site.  On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill.  Discovery, including depositions of past and present DP&L employees, was conducted in 2012.  On February 8, 2013, the Court granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by PRP group in their performing a Remediation Investigation and Feasibility Study.  That summary judgment ruling was appealed on March 4, 2013 and the appeal is pending.  DP&L is unable to predict the outcome of the appeal.  Additionally, the Court’s ruling does not address future litigation that may arise with respect to actual remediation costs.  While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations. 

Beginning in mid-2012, the USEPA began investigating whether explosive or other dangerous conditions exist under structures located at or near the South Dayton Dump landfill site.  In October 2012, DP&L received a request from the PRP group’s consultant to conduct additional soil and groundwater sampling on DP&L’s service center property.  After informal discussions with the USEPA, DP&L complied with this sampling request and the sampling was conducted in February 2013.  On February 28, 2013, the plaintiff’s group referenced above entered into an Administrative Settlement Agreement Consent Order (ASACO) that establishes procedures for further sub-slab testing under structures at the South Dayton Dump landfill site and remediation of vapor intrusion issues relating to trichloroethylene (TCE), percholorethylene (PCE), and methane.  On April 16, 2013, the plaintiff’s group filed a new complaint against DP&L and approximately 25 other defendants alleging that they share liability for these costs.  DP&L will oppose the allegations that it bears any responsibility under the February 2013 ASACO and will actively oppose any attempt that the plaintiffs group may have to expand the scope of the new complaint to resurrect issues dismissed by the Court in February 2013 under the first complaint.

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site.  Information available to DP&L does not demonstrate that it contributed hazardous substances to the site.  While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs).  While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L.  While the USEPA had indicated that the official release date for a proposed rule would be sometime in April 2013, it will likely be delayed until late 2013 or early 2014.  At present, DP&L is unable to predict the impact this initiative will have on its operations.

Regulation of Ash Ponds

In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and Stuart Stations.  Subsequently, the USEPA collected similar information for the Hutchings Station. 

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

In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds.  In May 2012, we received a draft report on the inspection.  DP&L submitted comments on the draft report in June 2012.  On March 14, 2013,DP&L received the final report on the inspection of the Killen Station ash pond inspection from the USEPA which included recommended actions.  DP&L is reviewing the final report and will submit a response to the USEPA.  There were no material compliance requirements included in the report.

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.  Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed.  At present, the timing for a final rule regulating coal combustion byproducts cannot be determined, but the USEPA has stated possibly by 2014.  If coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on its operations.

Notice of Violation Involving Co-Owned Units

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

Legal andOther Matters

In February 2007, DP&L filed a lawsuit in the United States District Court for the Southern District of Ohio against Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to Appalachian’s failure to supply approximately1.5 million tons of coal to two commonly owned stations 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.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2013
Entity Registrant Name	DPL INC
Entity Central Index Key	0000787250
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
DPL [Member]
Entity Common Stock, Shares Outstanding	1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Common Stock, Shares Outstanding	41,172,173

XML

Business Segments

3 Months Ended

Mar. 31, 2013

Business Segments [Abstract]

Business Segments

11.  Business Segments

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

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers.  Electricity for the segment’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers who are located in a 6,000 square mile area of West Central Ohio.  DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market.  DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier.  The Competitive Retail segment sells electricity to approximately 247,000 customers located throughout Ohio and in Illinois.  This number includes 137,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier, which was acquired by DPLER in February 2011.  Due to increased competition in Ohio, since 2010 we have increased the number of employees and resources assigned to manage the Competitive Retail segment and increased its marketing to customers.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM.  The majority of intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract.  The Competitive Retail segment has no transmission or generation assets.  The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

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

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

The following tables present financial information for each of DPL’s reportable business segments:

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended March 31, 2013
Revenues from external customers	$	271.8	$	117.3	$	5.5	$	-	$	394.6
Intersegment revenues		104.7		-		0.9		(105.6)		-
Total revenues		376.5		117.3		6.4		(105.6)		394.6
Fuel		88.1		-		0.5		-		88.6
Purchased power		94.1		105.7		0.2		(104.7)		95.3
Amortization of intangibles		-		-		1.8		-		1.8
Gross margin	$	194.3	$	11.6	$	3.9	$	(0.9)	$	208.9
Depreciation and amortization	$	33.6	$	0.1	$	(1.9)	$	-	$	31.8
Interest expense		9.3		0.2		21.2		(0.2)		30.5
Income tax expense (benefit)		9.6		0.9		(4.5)		-		6.0
Net income / (loss)		30.2		1.6		(11.9)		-		19.9
Cash capital expenditures		33.6		-		0.2		-		33.8
At March 31, 2013
Total assets	$	3,439.6	$	95.8	$	738.9	$	-	$	4,274.3

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended March 31, 2012
Revenues from external customers	$	312.8	$	112.1	$	9.1	$	-	$	434.0
Intersegment revenues		86.8		-		0.9		(87.7)		-
Total revenues		399.6		112.1		10.0		(87.7)		434.0
Fuel		95.6		-		1.8		-		97.4
Purchased power		84.9		96.7		-		(86.8)		94.8
Amortization of intangibles		-		-		27.8		-		27.8
Gross margin	$	219.1	$	15.4	$	(19.6)	$	(0.9)	$	214.0
Depreciation and amortization	$	34.7	$	0.2	$	(3.5)	$	-	$	31.4
Interest expense		9.6		0.2		20.0		(0.2)		29.6
Income tax expense (benefit)		17.3		3.4		(13.0)		-		7.7
Net income / (loss)		38.1		6.0		(22.4)		-		21.7
Cash capital expenditures		53.2		0.4		0.4		-		54.0
At December 31, 2012
Total assets	$	3,464.2	$	99.2	$	683.9	$	-	$	4,247.3

XML

Consolidated Statements of Comprehensive Income/(Loss) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	$ (0.1)	$ (0.2)
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(1.1)	(4.2)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(0.1)	0.6
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	(0.3)
THE DAYTON POWER AND LIGHT COMPANY [Member]
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	(0.2)	(0.2)
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	1.4	0.8
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	0.2	0.6
Income tax (expense)/benefit on prior service cost related to pension and postretirement activity	(0.5)	(3.0)
Income tax (expense)/benefit on net loss related to pension and postretirement activity		(0.3)
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity		$ (0.7)

XML

Income Taxes

3 Months Ended

Mar. 31, 2013

Income Taxes

6.  Income Taxes 

The following table details the effective tax rates for the three months ended March 31, 2013 and 2012. 

	Three months ended March 31,
	2013	2012
DPL	23.2%	26.0%

Income tax expense for the three months endedMarch 31, 2013 and 2012 was calculated using the estimated annual effective income tax rates for 2013 and 2012 of 30.2% and 25.6%, respectively.  Management estimates the annual effective tax rate based on its forecast of annual pre-tax income.  To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

For the three months ended March 31, 2013, DPL’s current period effective rate is less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 IRS examination in the first quarter of 2013.  The decrease in the effective rate compared to the same period in 2012 is also primarily due to the resolution of the 2008 IRS examination.

Deferred tax liabilities for DPL increased by approximately $23.3 million during the three months endedMarch 31, 2013 primarily related to the resolution of the 2008 IRS examination. 

The IRS began an examination of our 2008 Federal income tax return during the second quarter of 2010.  The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013.  As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense.

DP&L [Member]

Income Taxes

6.  Income Taxes 

The following table details the effective tax rates for the three months endedMarch 31, 2013 and 2012. 

	Three months ended March 31,
	2013	2012
DP&L	24.1%	31.3%

Income tax expense for the three months endedMarch 31, 2013 and 2012 was calculated using the estimated annual effective income tax rates for 2013 and 2012 of 28.8%and 31.1%, respectively.  Management estimates the annual effective tax rate based upon its forecast of annual pre-tax income.  To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.

For the three months ended March 31, 2013, DP&L’s current period effective rate is less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 IRS examination in the first quarter of 2013.  The decrease in the effective rate compared to the same period in 2012 is also primarily due to the resolution of the 2008 IRS examination. 

Deferred tax liabilities for DP&L increased by approximately $21.3 million during the three months endedMarch 31, 2013primarily related to the resolution of the 2008 IRS examination.  

The Internal Revenue Service began an examination of our 2008 federal income tax return during the second quarter of 2010.  The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013.  As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense.

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Debt Obligations

3 Months Ended

Mar. 31, 2013

Debt Obligations

5.  Debt Obligations 

Long-term debt

$ in millions	March 31, 2013		December 31, 2012
Pollution control series maturing in January 2028 - 4.7%	$	36.1	$	36.1
Pollution control series maturing in January 2034 - 4.8%		179.6		179.6
Pollution control series maturing in September 2036 - 4.8%		96.3		96.3
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligations		0.1		0.1
Total long-term debt at subsidiary		330.4		330.4
Bank term loan-maturing in August 2014 - variable rates: 2.46% - 2.47% and 2.22% - 2.47% (a)		425.0		425.0
Senior unsecured bonds maturing October 2016 - 6.5%		450.0		450.0
Senior unsecured bonds maturing October 2021 - 7.3%		800.0		800.0
Note to DPL Capital Trust II maturing in September 2031 - 8.125%		19.6		19.6
Total non-current portion - long-term debt - DPL	$	2,025.0	$	2,025.0

Current portion of long-term debt 

$ in millions	March 31, 2013		December 31, 2012
First mortgage bonds maturing in October 2013 - 5.125%	$	479.7	$	484.5
Pollution control series maturing in November 2040 - variable rates: 0.10% - 0.16% and 0.04% - 0.26% (a)		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.3		0.3
Total current portion - long-term debt - DPL	$	580.1	$	584.9

(a)  Range of interest rates for the three months endedMarch 31, 2013 and the twelve months ended December 31, 2012, respectively. 

At March 31, 2013, maturities of long-term debt, including capital lease obligations, are as follows:

$ in millions
Due within one year	$	570.4
Due within two years		425.2
Due within three years		0.1
Due within four years		450.1
Due within five years		0.2
Thereafter		1,152.8
Total maturities		2,598.8
Unamortized premiums and discounts		6.3
Total long-term debt	$	2,605.1

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

On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040.  In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds.  The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A.  This standby letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses.  If the standby letter of credit expires, this would trigger a mandatory tender of all of the outstanding bonds, therefore, we have reflected these outstanding bonds as a current liability.  DP&L is currently working to refinance this standby letter of credit.  Though not yet finalized it is expected that the new facility will be for three to five years under terms that are substantially similar to those of the existing facility. We currently have secured all of the bank commitments necessary to extend this facility and intend to finalize the amendment during the second quarter of 2013.  Fees associated with this standby letter of credit facility were not material during the three months ended March 31, 2013 and 2012.   

On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  The agreement provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.This agreement, originally for a three year term expiring on April 20, 2013, was extended through May 31, 2013 by an amendment dated April 11, 2013.  DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013,  DP&L had no outstanding letters of credit against this facility.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013,  DP&L had no outstanding letters of credit against this facility. 

Prior to the expiration of the DP&L amended revolving credit facility (that is now scheduled to expire on May 31, 2013) and in no case later than the end of the second quarter of 2013, DP&L intends to enter into a new $275.0 million to $350.0 million revolving credit facility and to extinguish both of the existing DP&L revolving credit facilities discussed above. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing.  The terms and conditions of this new revolving credit facility have not been finalized, but it is expected that they will be substantially similar to those of the existing DP&L revolving credit facilities.  As of the date of filing of this quarterly report on Form 10-Q, DP&L has the bank commitments required to close the new DP&L revolving credit facility.

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

On August 24, 2011, DPL entered into a $125.0 million unsecured revolving credit agreement with a syndicated bank group.  This agreement is for a three year term expiring on August 24, 2014.  The size of the facility was reduced from $125.0 million to $75.0 million as part of an amendment dated October 19, 2012 that was negotiated between DPL and the syndicated bank group.  DPL had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility may also be used to issue letters of credit up to the $75.0 million limit.  As of March 31, 2013,  DPL had no outstanding letters of credit against this facility.   

On August 24, 2011, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group.  This agreement is for a three year term expiring on August 24, 2014.DPL has borrowed the entire $425.0 million available under the facility at March 31, 2013 and December 31, 2012.  Fees associated with this term loan were not material during the three months ended March 31, 2013 and 2012. 

Prior to the end of the second quarter, DPL intends to enter into a new $75.0 million to $150.0 million revolving credit facility and to extinguish the existing $75.0 million facility. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing. Contemporaneously, DPL intends to refinance a portion of its $425.0 million term loan, and repay the balance of the currently outstanding term loan with cash.  The terms and conditions of this new revolving credit facility and new term loan have not been finalized, but it is expected they will be at market for these types of transactions.  As of the date of filing this quarterly report on Form 10-Q, DPL has secured all of the bank commitments required to close the new DPL revolving credit facility and the new DPL term loan.

DPL’s unsecured revolving credit agreement and DPL’s unsecured term loan each have two financial covenants, one of which was changed as part of amendments dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups.  The first financial covenant, originally a Total Debt to Capitalization ratio, was changed, effective September 30, 2012, to a Total Debt to EBITDA ratio.  The Total Debt to EBITDA ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters.   

The second financial covenant is an EBITDA to Interest Expense ratio.  The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.   

The amendments, dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups, restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities.

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

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

DP&L [Member]

Debt Obligations

5.  Debt Obligations 

Long-term debt

$ in millions	March 31, 2013		December 31, 2012
Pollution control series maturing in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series maturing in January 2034 - 4.8%		179.1		179.1
Pollution control series maturing in September 2036 - 4.8%		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligation		0.1		0.1
Unamortized debt discount		(0.1)		(0.1)
Total non-current portion - long-term debt - DP&L	$	332.7	$	332.7

Current portion of long-term debt

$ in millions	March 31, 2013		December 31, 2012
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0	$	470.0
Pollution control series maturing in November 2040 - variable rates: 0.10% - 0.16% and 0.04% - 0.26% (a)		100.0		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.3		0.3
Total current portion - long-term debt - DP&L	$	570.4	$	570.4

(a) Range of interest rates for the three months ended March 31, 2013 and the twelve months ended December 31, 2012, respectively. 

At March 31, 2013, maturities of long-term debt, including capital lease obligations, are as follows:

$ in millions
Due within one year	$	570.4
Due within two years		0.2
Due within three years		0.1
Due within four years		0.1
Due within five years		0.1
Thereafter		332.3
Total maturities		903.2
Unamortized discounts		(0.1)
Total long-term debt	$	903.1

On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040.  In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds.  The payment of principal and interest on each series of the bonds when due is backed by a standby letter of credit issued by JPMorgan Chase Bank, N.A.  This standby letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses.  If the standby letter of credit expires, this would trigger a mandatory tender of all of the outstanding bonds, therefore, we have reflected these outstanding bonds as a current liability.  Fees associated with this standby letter of credit facility were not material during the three months ended March 31, 2013 and 2012.   

On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  The agreement provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.This agreement, originally for a three year term expiring on April 20, 2013, was extended through May 31, 2013 by an amendment dated April 11, 2013 that was negotiated between DP&L and the syndicated bank group. DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013,  DP&L had no outstanding letters of credit against this facility.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group.  This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million.DP&L had no outstanding borrowings under this credit facility at March 31, 2013 and December 31, 2012.  Fees associated with this revolving credit facility were not material during the three months ended March 31, 2013 and 2012.  This facility also contains a $50.0 million letter of credit sublimit.  As of March 31, 2013,  DP&L had no outstanding letters of credit against this facility. 

Prior to the expiration of the DP&L amended revolving credit facility (that is now scheduled to expire on May 31, 2013) and in no case later than the end of the second quarter of 2013, DP&L intends to enter into a new $275.0 million to $350.0 million revolving credit facility and to extinguish both of the existing DP&L revolving credit facilities discussed above. It is expected that this new facility will have a three to five year term and an option to further increase the potential borrowing.  The terms and conditions of this new revolving credit facility have not been finalized, but it is expected that they will be substantially similar to those of the existing DP&L revolving credit facilities.  As of the date of filing of this quarterly report on Form 10-Q, DP&L has the bank commitments required to close the new DP&L revolving credit facility.

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

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 (Tables)

3 Months Ended

Mar. 31, 2013

Ownership Interests

	DP&L Share			DP&L Investment
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)	Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Beckjord Unit 6	50.0	207	$	1	$	1	$	-	No
Conesville Unit 4	16.5	129		42		4		12	Yes
East Bend Station	31.0	186		8		3		3	Yes
Killen Station	67.0	402		301		4		9	Yes
Miami Fort Units 7 and 8	36.0	368		212		9		3	Yes
Stuart Station	35.0	808		202		7		10	Yes
Zimmer Station	28.1	365		169		15		2	Yes
Transmission (at varying percentages)		n/a		40		2		-
Total		2,465	$	975	$	45	$	39
Wholly owned production station:
Hutchings Station	100.0	365	$	-	$	-	$	-	No

DP&L [Member]

Ownership Interests

	DP&L Share			DP&L Investment
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)	Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Beckjord Unit 6	50.0	207	$	76	$	64	$	-	No
Conesville Unit 4	16.5	129		28		2		4	Yes
East Bend Station	31.0	186		209		137		3	Yes
Killen Station	67.0	402		617		302		9	Yes
Miami Fort Units 7 and 8	36.0	368		361		148		3	Yes
Stuart Station	35.0	808		744		297		10	Yes
Zimmer Station	28.1	365		1,097		644		2	Yes
Transmission (at varying percentages)				97		59		-
Total		2,465	$	3,229	$	1,653	$	31
Wholly owned production station:
Hutchings Station	100.0	365	$	-	$	-	$	-	No

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Summary of Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2013

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 operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared.  Refer to Note 11 for more information relating to these reportable segments.  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.   

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

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers.  DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011.  DPLER has approximately 247,000 customers currently located throughout Ohio and Illinois.  DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations.  DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves. 

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

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

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

DPL and its subsidiaries employed 1,475 people as of March 31, 2013, of which 1,412 employees were employed by DP&L.  Approximately 53% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014. 

Financial Statement Presentation

Financial Statement Presentation  

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP.  DP&L’s undivided ownership interests in certain coal-fired generating facilities and numerous transmission facilities are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date for DPL.  Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statement of Operations.  See Note 4 for more information. 

All material intercompany accounts and transactions are eliminated in consolidation.   

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X.  Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report.  Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.   

In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2013; our results of operations for the three months ended March 31, 2013 and 2012 and our cash flows for the three months ended March 31, 2013 and 2012.  Unless otherwise noted, all adjustments are normal and recurring in nature.  Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013. 

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

Goodwill Impairment

Goodwill Impairment

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

Receivables

Sale of Receivables 

In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy.  These sales are at face value for cash at the amounts billed for DPLER customers’ use of energy.  Total receivables sold to Duke Energy during the three months endedMarch 31, 2013 and 2012 were $4.5 million and  $2.0 million, respectively.  Similarly, MC Squared sells receivables from their customers in ComEd territory to ComEd.  Total receivables sold to ComEd during the three months endedMarch 31, 2013 and 2012 were $16.9 million and $0.0million, respectively

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.  For non-regulated property including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. 

Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.  The total AFUDC and capitalized interest was $0.3 million and $1.4 million during the three months endedMarch 31, 2013 and 2012, respectively.  

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

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

Intangibles

Intangibles 

Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP.  Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances.  In addition, we recorded emission allowances at their fair value as of the Merger date.  Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.  During the three months ended March 31, 2013 and 2012,  DPL had no gains from the sale of emission allowances.   

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

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities 

DPL collects certain excise taxes levied by state or local governments from its customers.  These taxes are accounted for on a net basis and recorded as a reduction in revenues.  The amounts for the three months endedMarch 31, 2013 and 2012 were $13.4 million and $12.9 million, respectively

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Issued Accounting Standards 

Offsetting Assets and Liabilities

The FASB recently issued ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”to limit the scope of ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” to derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions.  This ASU is effective for annual and interim periods beginning on or after January 1, 2013.  The FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220):  Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards  

Offsetting Assets and Liabilities 

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

Testing Indefinite-Lived Intangible Assets for Impairments 

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012.  We adopted this ASU on January 1, 2013.  This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.”  ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30.  This rule did not have a material effect on our overall results of operations, financial position or cash flows.

DP&L [Member]

Description of Business

Description of Business  

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  Electricity for DP&L's24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 514,000 retail customers.  Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.  DP&L is a wholly owned subsidiary of DPL. 

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

DP&L’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. 

DP&L employed 1,412 people as of March 31, 2013.  Approximately 55% of all employees are under a collective bargaining agreement which expires on October 31, 2014. 

Financial Statement Presentation

Financial Statement Presentation  

DP&L does not have any subsidiaries.  DP&L has undivided ownership interests in seven electric generating facilities and numerous transmission facilities which are included in the financial statements at amortized cost.  Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statement of Operations.  See Note 4 for more information.   

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X.  Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report.  Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.   

In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31, 2013; our results of operations for the three months ended March 31, 2013 and 2012 and our cash flows for the three months ended March 31, 2013 and 2012.  Unless otherwise noted, all adjustments are normal and recurring in nature.  Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013. 

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

Property, Plant and Equipment  

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment.  Property, plant and equipment are stated at cost.  For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC).  AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects.  For non-regulated property including unregulated generation property, cost is similarly defined except financing costs are reflected as capitalized interest without an equity component. 

Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators.  The total of AFUDC and capitalized interest was $0.3 million and $1.4 million for the three months endedMarch 31, 2013 and 2012, respectively. 

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

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

Intangibles

Intangibles 

Intangibles consist of emission allowances and renewable energy credits.  Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances.  Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized.  Emission allowances are amortized as they are used in our operations.  Renewable energy credits are amortized as they are used or retired.  During the three months ended March 31, 2013 and 2012,  DP&L had no gains from the sale of emission allowances.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

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.  These taxes are accounted for on a net basis and are recorded as a reduction in revenues.  The amounts for the three months endedMarch 31, 2013 and 2012 were $13.4 million and $12.9 million, respectively.

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Issued Accounting Standards 

Offsetting Assets and Liabilities

The FASB recently issued ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”to limit the scope of ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” to derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities borrowing and lending transactions.  This ASU became effective for annual and interim periods beginning on or after January 1, 2013.  The FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220):  Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or other comprehensive income in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts.  We adopted this rule which resulted in enhanced disclosures.  This did not have a material effect on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards  

Offsetting Assets and Liabilities 

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

Testing Indefinite-Lived Intangible Assets for Impairments 

In July 2012, the FASB issued ASU 2012-02 “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02) effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012.  We adopted this ASU on January 1, 2013.  This standard updates FASC Topic 350 “Intangibles-Goodwill and Other.”  ASU 2012-02 permits an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired as a basis for determining whether it is necessary to perform the quantitative impairment test in accordance with FASC Subtopic 350-30.  These new rules did not have a material impact on our overall results of operations, financial position or cash flows.

Related Party Transactions

Related Party Transactions 

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

XML

Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities

9.  Derivative Instruments and Hedging Activities 

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

At March 31, 2013,  DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		2.8		-		2.8
Heating Oil Futures		Mark to Market	Gallons		1,890.0		-		1,890.0
Forward Power Contracts		Cash Flow Hedge	MWh		842.6		(2,040.9)		(1,198.3)
Forward Power Contracts		Mark to Market	MWh		2,221.4		(7,069.8)		(4,848.4)
Interest Rate Swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

At December 31, 2012,  DPL had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating Oil Futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward Power Contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward Power Contracts		Mark to Market	MWh		2,510.7		(4,760.4)		(2,249.7)
Interest Rate Swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

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 is determined by observable market prices available as of the balance sheet dates and will continue to fluctuate with changes in market prices up to contract expiration.  The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring.  The ineffective portion of the cash flow hedge is recognized in earnings in the current period.  All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. 

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

We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt.  Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  We do not hedge all interest rate exposure.  We reclassify gains and losses on interest rate derivative hedges related to debt financings from AOCI into earnings in those periods in which hedged interest payments occur.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31, 2013 and 2012: 

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(3.0)	$	0.5	$	0.3	$	(0.8)
Net gains / (losses) associated with current period hedging transactions		(2.9)		4.1		(1.5)		9.1
Net gains reclassified to earnings
Interest Expense		-		-		-		0.2
Revenues		(0.3)		-		(1.2)		-
Purchased Power		0.5		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	(5.7)	$	4.6	$	(2.3)	$	8.5
Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest Expense	$	-	$	-	$	-	$	(1.6)
Revenues	$	-	$	-	$	-	$	-
Purchased Power	$	-	$	-	$	-	$	-
Portion expected to be reclassified to earnings in the next twelve months (a)	$	9.9	$	-
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21		5

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

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.  FTRs, heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts are currently marked to market. 

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

The following tables show the amount and classification within the Condensed Consolidated Statements of Results of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three months ended March 31, 2013 and 2012. 

For the three months ended March 31, 2013
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	-	$	-	$	-	$	(16.5)	$	(16.5)
Realized gain / (loss)		-		-		0.5		0.4		0.9
Total	$	-	$	-	$	0.5	$	(16.1)	$	(15.6)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	-	$	-	$	-	$	-	$	-
Regulatory (asset) / liability		-		-		-		-		-
Recorded in Income Statement:  gain / (loss)
Revenue		-		-		-		-		-
Purchased Power		-		-		0.5		(16.1)		(15.6)
Fuel		-		-		-		-		-
O&M		-		-		-		-		-
Total	$	-	$	-	$	0.5	$	(16.1)	$	(15.6)

For the three months ended March 31, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(7.8)	$	(0.1)	$	(0.1)	$	1.4	$	(6.6)
Realized gain / (loss)		(5.0)		0.9		(0.2)		(2.3)		(6.6)
Total	$	(12.8)	$	0.8	$	(0.3)	$	(0.9)	$	(13.2)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	(3.5)	$	-	$	-	$	-	$	(3.5)
Regulatory (asset) / liability		(1.1)		0.1		-		-		(1.0)
Recorded in Income Statement:  gain / (loss)
Revenue		-		-		-		3.4		3.4
Purchased Power		-		-		(0.3)		(4.3)		(4.6)
Fuel		(8.2)		0.6		-		-		(7.6)
O&M		-		0.1		-		-		0.1
Total	$	(12.8)	$	0.8	$	(0.3)	$	(0.9)	$	(13.2)

DPL has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.  The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.  The following table shows the fair value and balance sheet classification of DPL’s derivative instruments at March 31, 2013: 

Fair Values of Derivative Instruments
at March 31, 2013
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.2	$	(0.1)	$	-	$	0.1
Forward Power Contracts	MTM		4.5		(3.8)		-		0.7
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	MTM		1.1		(0.6)		-		0.5
Total assets		$	6.0	$	(4.5)	$	(0.2)	$	1.3
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	8.9	$	(0.1)	$	(6.2)	$	2.6
Interest Rate Hedge	Cash Flow		23.2		-		-		23.2
Forward Power Contracts	MTM		9.9		(3.8)		(5.5)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.9		-		(1.1)		0.8
Forward Power Contracts	MTM		2.6		(0.6)		(1.5)		0.5
Total liabilities		$	46.5	$	(4.5)	$	(14.3)	$	27.7

As of March 31, 2013, the table above includes Forward Power Contracts in a short-term asset position of $4.7 million and a long-term asset position of $1.1 million.  This table does not include an asset position of $5.8 million of Forward Power Contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contracts. 

The following table shows the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2012: 

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward Power Contracts	MTM		2.7		(1.5)		-		1.2
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	Cash Flow		0.5		(0.5)		-		-
Forward Power Contracts	MTM		3.6		(0.6)		-		3.0
Total assets		$	7.5	$	(3.1)	$	(0.2)	$	4.2
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
Interest Rate Hedge	Cash Flow		29.5		-		-		29.5
FTRs	MTM		0.1		-		-		0.1
Forward Power Contracts	MTM		4.1		(1.5)		(2.0)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward Power Contracts	MTM		0.8		(0.6)		(0.1)		0.1
Total liabilities		$	42.7	$	(3.1)	$	(5.1)	$	34.5

As of December 31, 2012, the table above includes Forward power contracts in a short-term asset position of $2.7 million and a long-term asset position of $3.6 million.  This table does not include a short-term asset position of $7.2 million or a long-term asset position of $1.0 million of Forward power contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contracts.

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.   

The aggregate fair value of DPL’s commodity derivative instruments that are in a MTM loss position at March 31, 2013 is $23.3 million.  This amount is offset by $14.3million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts.  This liability position is further offset by the asset position of counterparties with master netting agreements of $4.5 million.  If our counterparties were to call for collateral, we could have to post collateral for the remaining $4.5 million.

DP&L [Member]

Derivative Instruments and Hedging Activities

9.  Derivative Instruments and Hedging Activities 

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

At March 31, 2013,  DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		2.8		-		2.8
Heating Oil Futures		Mark to Market	Gallons		1,890.0		-		1,890.0
Forward Power Contracts		Cash Flow Hedge	MWh		842.6		(2,040.9)		(1,198.3)
Forward Power Contracts		Mark to Market	MWh		2,221.4		(7,069.8)		(4,848.4)

At December 31, 2012,  DP&L had the following outstanding derivative instruments:

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating Oil Futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward Power Contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward Power Contracts		Mark to Market	MWh		2,296.6		(4,760.4)		(2,463.8)

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 is determined by observable market prices available as of the balance sheet dates and will continue to fluctuate with changes in market prices up to contract expiration.  The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring.  The ineffective portion of the cash flow hedge is recognized in earnings in the current period.  All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges. 

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. 

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months endedMarch 31, 2013 and 2012: 

	Three months ended				Three months ended
	March 31, 2013				March 31, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(4.7)	$	7.3	$	(0.8)	$	9.8
Net gains / (losses) associated with current period hedging transactions		(2.6)		-		(1.5)		-
Net gains reclassified to earnings
Interest Expense		-		(0.6)		-		(0.6)
Revenues		(0.3)		-		(1.2)		-
Purchased Power		0.7		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	(6.9)	$	6.7	$	(3.4)	$	9.2
Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest Expense	$	-	$	-
Revenues	$	-	$	-
Purchased Power	$	-	$	-
Portion expected to be reclassified to earnings in the next twelve months (a)	$	8.8	$	-
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		21		5

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

Mark to Market Accounting 

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

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

The following tables show the amount and classification within the statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three months ended March 31, 2013 and 2012: 

For the three months ended March 31, 2013
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	-	$	-	$	-	$	(10.4)	$	(10.4)
Realized gain / (loss)		-		-		0.5		0.7		1.2
Total	$	-	$	-	$	0.5	$	(9.7)	$	(9.2)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	-	$	-	$	-	$	-	$	-
Regulatory (asset) / liability		-		-		-		-		-
Recorded in Income Statement: gain / (loss)
Revenue		-		-		-		(1.1)		(1.1)
Purchased Power		-		-		0.5		(8.6)		(8.1)
Fuel		-		-		-		-		-
O&M		-		-		-		-		-
Total	$	-	$	-	$	0.5	$	(9.7)	$	(9.2)

For the three months ended March 31, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(7.8)	$	(0.1)	$	(0.1)	$	-	$	(8.0)
Realized gain / (loss)		(5.0)		0.9		(0.2)		-		(4.3)
Total	$	(12.8)	$	0.8	$	(0.3)	$	-	$	(12.3)
Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	(3.5)	$	-	$	-	$	-	$	(3.5)
Regulatory (asset) / liability		(1.1)		0.1		-		-		(1.0)
Recorded in Income Statement: gain / (loss)
Revenue		-		-		-		1.6		1.6
Purchased Power		-		-		(0.3)		(1.6)		(1.9)
Fuel		(8.2)		0.6		-		-		(7.6)
O&M		-		0.1		-		-		0.1
Total	$	(12.8)	$	0.8	$	(0.3)	$	-	$	(12.3)

DP&L has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.  The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.  The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments at March 31, 2013:

Fair Values of Derivative Instruments
at March 31, 2013
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.2	$	(0.1)	$	-	$	0.1
Forward Power Contracts	MTM		5.3		(3.8)		-		1.5
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	MTM		1.1		(0.6)		-		0.5
Total assets		$	6.8	$	(4.5)	$	(0.2)	$	2.1
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	8.9	$	(0.1)	$	(6.2)	$	2.6
Forward Power Contracts	MTM		9.5		(3.8)		(5.1)		0.6
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.9		-		(1.1)		0.8
Forward Power Contracts	MTM		2.6		(0.6)		(1.5)		0.5
Total liabilities		$	22.9	$	(4.5)	$	(13.9)	$	4.5

The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2012:

Fair Values of Derivative Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral Received		Net Amount
Assets
Short-term Derivative Positions (presented in Other Current Assets)
Forward Power Contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward Power Contracts	MTM		2.8		(1.5)		-		1.3
Heating Oil Futures	MTM		0.2		-		(0.2)		-
Long-term Derivative Positions (presented in Other Deferred Assets)
Forward Power Contracts	Cash Flow		0.5		(0.5)		-		-
Forward Power Contracts	MTM		3.6		(0.6)		-		3.0
Total assets		$	7.6	$	(3.1)	$	(0.2)	$	4.3
Liabilities
Short-term Derivative Positions (presented in Other Current Liabilities)
Forward Power Contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
FTRs	MTM		0.1		-		-		0.1
Forward Power Contracts	MTM		2.7		(1.5)		(0.5)		0.7
Long-term Derivative Positions (presented in Other Deferred Liabilities)
Forward Power Contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward Power Contracts	MTM		0.7		(0.6)		-		0.1
Total liabilities		$	11.7	$	(3.1)	$	(3.5)	$	5.1

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.   

The aggregate fair value of DP&L’s commodity derivative instruments that are in a MTM loss position at March 31, 2013 is $22.9 million.  This amount is offset by $13.9 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts.  This liability position is further offset by the asset position of counterparties with master netting agreements of $4.5 million.  If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $4.5 million.

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Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
DP&L [Member]
Derivative Liability, Fair Value	$ 22.9
Total Assets [Member]
Derivative Asset, Fair Value	6.0	7.5
Derivative, Fair Value, Net	1.3	4.2
Derivative, Collateral, net	(0.2)	(0.2)
Derivative, Fair Value, Offset, Net	(4.5)	(3.1)
Total Assets [Member] | DP&L [Member]
Derivative Asset, Fair Value	6.8	7.6
Derivative, Fair Value, Net	2.1	4.3
Derivative, Collateral, net	(0.2)	(0.2)
Derivative, Fair Value, Offset, Net	(4.5)	(3.1)
Total Liabilities [Member]
Derivative, Fair Value, Net	27.7	34.5
Derivative, Collateral, net	(14.3)	(5.1)
Derivative, Fair Value, Offset, Net	(4.5)	(3.1)
Derivative Liability, Fair Value	46.5	42.7
Total Liabilities [Member] | DP&L [Member]
Derivative, Fair Value, Net	4.5	5.1
Derivative, Collateral, net	(13.9)	(3.5)
Derivative, Fair Value, Offset, Net	(4.5)	(3.1)
Derivative Liability, Fair Value	22.9	11.7
Not Designated as Hedging Instrument [Member]
Derivative Liability, Fair Value	23.3
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	4.5	2.7
Derivative, Fair Value, Net	0.7	1.2
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | DP&L [Member]
Derivative Asset, Fair Value	5.3	2.8
Derivative, Fair Value, Net	1.5	1.3
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative, Fair Value, Net	0.6	0.6
Derivative, Collateral, net	(5.5)	(2.0)
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Derivative Liability, Fair Value	9.9	4.1
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | DP&L [Member]
Derivative, Fair Value, Net	0.6	0.7
Derivative, Collateral, net	(5.1)	(0.5)
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Derivative Liability, Fair Value	9.5	2.7
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative, Fair Value, Net	0.5	0.1
Derivative, Collateral, net	(1.5)	(0.1)
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Derivative Liability, Fair Value	2.6	0.8
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | DP&L [Member]
Derivative, Fair Value, Net	0.5	0.1
Derivative, Collateral, net	(1.5)
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Derivative Liability, Fair Value	2.6	0.7
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	1.1	3.6
Derivative, Fair Value, Net	0.5	3.0
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | DP&L [Member]
Derivative Asset, Fair Value	1.1	3.6
Derivative, Fair Value, Net	0.5	3.0
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative, Fair Value, Net		0.1
Derivative Liability, Fair Value		0.1
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | DP&L [Member]
Derivative, Fair Value, Net		0.1
Derivative Liability, Fair Value		0.1
Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	0.2	0.2
Derivative, Collateral, net	(0.2)	(0.2)
Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | DP&L [Member]
Derivative Asset, Fair Value	0.2	0.2
Derivative, Collateral, net	(0.2)	(0.2)
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	0.2	0.5
Derivative, Fair Value, Net	0.1
Derivative, Fair Value, Offset, Net	(0.1)	(0.5)
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | DP&L [Member]
Derivative Asset, Fair Value	0.2	0.5
Derivative, Fair Value, Net	0.1
Derivative, Fair Value, Offset, Net	(0.1)	(0.5)
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative, Fair Value, Net	2.6	4.1
Derivative, Collateral, net	(6.2)	(2.1)
Derivative, Fair Value, Offset, Net	(0.1)	(0.5)
Derivative Liability, Fair Value	8.9	6.7
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | DP&L [Member]
Derivative, Fair Value, Net	2.6	4.1
Derivative, Collateral, net	(6.2)	(2.1)
Derivative, Fair Value, Offset, Net	(0.1)	(0.5)
Derivative Liability, Fair Value	8.9	6.7
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative, Fair Value, Net	0.8	0.1
Derivative, Collateral, net	(1.1)	(0.9)
Derivative, Fair Value, Offset, Net		(0.5)
Derivative Liability, Fair Value	1.9	1.5
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | DP&L [Member]
Derivative, Fair Value, Net	0.8	0.1
Derivative, Collateral, net	(1.1)	(0.9)
Derivative, Fair Value, Offset, Net		(0.5)
Derivative Liability, Fair Value	1.9	1.5
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value		0.5
Derivative, Fair Value, Offset, Net		(0.5)
Cash Flow Hedging [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | DP&L [Member]
Derivative Asset, Fair Value		0.5
Derivative, Fair Value, Offset, Net		(0.5)
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative, Fair Value, Net	23.2	29.5
Derivative Liability, Fair Value	$ 23.2	$ 29.5

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Pension and Postretirement Benefits

3 Months Ended

Mar. 31, 2013

Pension and Postretirement Benefits

7.  Pension and Postretirement Benefits 

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

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three months ended March 31, 2013 or 2012. 

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

The net periodic benefit cost/(income) of the pension and postretirement benefit plans for the three months ended March 31, 2013 and 2012 was: 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended March 31,		Three months ended March 31,		Three months ended March 31,		Three months ended March 31,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	0.1	$	0.1
Interest cost		3.9		4.3		0.2		0.3
Expected return on assets (a)		(5.9)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		1.2		1.2		(0.1)		(0.2)
Prior service cost		0.4		0.4		-		-
Net periodic benefit cost / (income)	$	1.4	$	1.7	$	0.1	$	0.1

(a)   For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $336.0 million, respectively. 

Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated Future Benefit Payments and Medicare Part D Reimbursements
$ in millions	Pension		Postretirement
2013	$	16.6	$	1.7
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		124.4		6.8

DP&L [Member]

Pension and Postretirement Benefits

7.  Pension and Postretirement Benefits 

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

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three months endedMarch 31, 2013 or 2012.

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

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months endedMarch 31, 2013 and 2012 was: 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended March 31,		Three months ended March 31,		Three months ended March 31,		Three months ended March 31,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	0.1	$	0.1
Interest cost		3.9		4.3		0.2		0.3
Expected return on assets (a)		(5.9)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		2.3		2.7		(0.1)		(0.2)
Prior service cost		0.7		0.8		-		-
Net periodic benefit cost / (income)	$	2.8	$	3.6	$	0.1	$	0.1

(a)   For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used.  GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $335.0 million, respectively. 

Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated Future Benefit Payments and Medicare Part D Reimbursements
$ in millions	Pension		Postretirement
2013	$	16.6	$	1.7
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		124.4		6.8

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Fair Value Measurements

3 Months Ended

Mar. 31, 2013

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 value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future. 

The following table presents the fair value and cost of our non-derivative instruments at March 31, 2013 and December 31, 2012.  See also Note 9 for the fair values of our derivative instruments. 

	At March 31,				At December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities		4.0		5.7		4.0		5.1
Debt Securities		4.5		4.9		4.6		5.0
Multi-Strategy Fund		0.3		0.3		0.3		0.3
Total Assets	$	9.0	$	11.1	$	9.1	$	10.6
Liabilities
Debt	$	2,605.1	$	2,705.4	$	2,609.9	$	2,707.1

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Consolidated Balance Sheet at their gross fair value, except for Debt which is presented at amortized cost.

Debt 

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

Master Trust Assets 

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

DPL had $1.2 million ($0.8million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2013 and $0.7 million ($0.5 million after tax) of unrealized gains immaterial unrealized losses in AOCI at December 31, 2012. 

$0.1 million ($0.1 million after tax) of various investments were sold during the quarter to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  

Net Asset Value (NAV) per Unit 

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of March 31, 2013 and December 31, 2012.  These assets are part of the Master Trust.  Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date.  Investments that have restrictions on the redemption of the investments are Level 3 inputs.  As of March 31, 2013,  DPL did not have any investments for sale at a price different from the NAV per unit. 

Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at March 31, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	-	Immediate
Equity Securities (b)		5.7		5.1		-	Immediate
Debt Securities (c)		4.9		5.0		-	Immediate
Multi-Strategy Fund (d)		0.3		0.3		-	Immediate
Total	$	11.1	$	10.6	$	-

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

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

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

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

The fair value of assets and liabilities at March 31, 2013 and December 31, 2012 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows: 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.7		-		5.7		-
Debt Securities		4.9		-		4.9		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		11.1		0.2		10.9		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		5.8		-		5.8		-
Total Derivative Assets		6.0		0.2		5.8		-
Total Assets	$	17.1	$	0.4	$	16.7	$	-
Liabilities
Derivative Liabilities
Interest Rate Hedge	$	23.2	$	-	$	23.2	$	-
Forward Power Contracts		23.3		-		23.3		-
Total Derivative Liabilities		46.5		-		46.5		-
Long-term Debt		2,705.4		-		2,686.6		18.8
Total Liabilities	$	2,751.9	$	-	$	2,733.1	$	18.8

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.3		-		6.3		-
Total Derivative Assets		6.5		0.2		6.3		-
Total Assets	$	17.1	$	0.4	$	16.7	$	-
Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Interest Rate Hedge		29.5		-		29.5		-
Forward Power Contracts		13.1		-		13.1		-
Total Derivative Liabilities		42.7		-		42.6		0.1
Long-term debt		2,707.1		-		2,688.2		18.9
Total Liabilities	$	2,749.8	$	-	$	2,730.8	$	19.0

We use the market approach to value our financial instruments.  Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents.  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 forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market).  Other Level 2 assets include:  open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit; and interest rate hedges, which use observable inputs to populate a pricing model.  Financial transmission rights are considered a Level 3 input because the monthly auctions are considered inactive. 

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

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

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

Non-recurring Fair Value Measurements 

We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  Additions to AROs were not material during the three months endedMarch 31, 2013 and 2012. 

Cash Equivalents 

DPL had $175.0 million and $130.0 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012, respectively.  The money market funds have quoted prices that are generally equivalent to par and are considered Level 1.

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 method is available to us.  The value of our financial instruments represents our best estimates of fair value, which may not be the value realized in the future.  The following table presents the fair value and cost of our non-derivative instruments at March 31, 2013 and December 31, 2012.  See also Note 9 for the fair values of our derivative instruments. 

	At March 31,				At December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities		4.0		5.7		4.0		5.1
Debt Securities		4.5		4.9		4.6		5.0
Multi-Strategy Fund		0.3		0.3		0.3		0.3
Total Assets	$	9.0	$	11.1	$	9.1	$	10.6
Liabilities
Debt	$	903.1	$	921.8	$	903.1	$	926.9

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed Consolidated Balance Sheet at their gross fair value, except for Debt which is presented at amortized cost.

Debt 

The fair value of debt is based on current public market prices for disclosure purposes only.  Unrealized gains or losses are not recognized in the financial statements because debt is presented at amortized cost in the financial statements.  The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2013 to 2061. 

Master Trust Assets 

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes.  These assets are primarily comprised of open-ended mutual funds which are valued using the net asset value per unit.  These investments are recorded at fair value within Other assets on the balance sheets and classified as available for sale.  Any unrealized gains or losses are recorded in AOCI until the securities are sold.   

DP&L had $2.1 million ($1.4 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2013 and $1.6 million ($1.0 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2012.   

$0.1 million ($0.1 million after tax) of various investments were sold during the quarter to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  

Net Asset Value (NAV) per Unit 

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of March 31, 2013.  These assets are part of the Master Trust.  Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date.  Investments that have restrictions on the redemption of the investments are Level 3 inputs.  At March 31, 2013,  DP&L did not have any investments for sale at a price different from the NAV per unit. 

Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at March 31, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	-	Immediate
Equity Securities (b)		5.7		5.1		-	Immediate
Debt Securities (c)		4.9		5.0		-	Immediate
Multi-Strategy Fund (d)		0.3		0.3		-	Immediate
Total	$	11.1	$	10.6	$	-

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

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

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

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

The fair value of assets and liabilities at March 31, 2013 and December 31, 2012 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows: 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.7		-		5.7		-
Debt Securities		4.9		-		4.9		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		11.1		0.2		10.9		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.6		-		6.6		-
Total Derivative Assets		6.8		0.2		6.6		-
Total Assets	$	17.9	$	0.4	$	17.5	$	-
Liabilities
Derivative Liabilities
Forward Power Contracts	$	22.9	$	-	$	22.9	$	-
Total Derivative Liabilities		22.9		-		22.9		-
Long-term Debt		921.8		-		903.0		18.8
Total Liabilities	$	944.7	$	-	$	925.9	$	18.8

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		7.3		-		7.3		-
Total Derivative Assets		7.5		0.2		7.3		-
Total Assets	$	18.1	$	0.4	$	17.7	$	-
Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Forward Power Contracts		11.6		-		11.6		-
Total Derivative Liabilities		11.7		-		11.6		0.1
Long-term debt		926.9		-		908.0		18.9
Total Liabilities	$	938.6	$	-	$	919.6	$	19.0

We use the market approach to value our financial instruments.  Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents.  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 forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market).  Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit; and interest rate hedges, which use observable inputs to populate a pricing model.  Financial transmission rights are considered a Level 3 input because the monthly auctions are considered inactive. 

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

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

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

Non-recurring Fair Value Measurements 

We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  Additions to AROs were not material during the three months ended March 31, 2013 and 2012. 

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Common Shareholders' Equity (DP&L [Member])

3 Months Ended

Mar. 31, 2013

DP&L [Member]

Common Shareholders' Equity

10.  Shareholder’s Equity 

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at March 31, 2013.  All common shares are held by DP&L’s parent, DPL. 

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

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Business Segments (Narrative) (Details)	3 Months Ended
	Mar. 31, 2013 sqmi
Service area, counties	24
Service area, square miles	6,000
Number of coal fired power plants	8
Approximate number of retail customers	514,000
Approximate Number Of Competitive Retail Customers	247,000
Number of MC Squared Retail Customers	137,000
DP&L [Member]
Service area, counties	24
Service area, square miles	6,000
Number of coal fired power plants	8
Approximate number of retail customers	514,000

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Commitments, Environmental, Legal (Schedule Of Contractual Obligations And Commercial Commitments) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Contractual Obligations, Commercial Commitments And Contingencies [Line Items]
Total long-term debt	$ 2,025.0	$ 2,025.0
Long-term debt, Less than 1 year	570.4
Long-term debt, More than 5 years	1,152.8
DP&L [Member]
Contractual Obligations, Commercial Commitments And Contingencies [Line Items]
Total long-term debt	332.7	332.7
Long-term debt, Less than 1 year	570.4
Long-term debt, More than 5 years	$ 332.3

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Summary of Significant Accounting Policies (Financial Statement Presentation) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Overview and Summary of Significant Accounting Policies [Abstract]
Goodwill	$ 759.1	$ 759.1

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Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Long Term Debt Range Adjusted To Fair Value at Merger Start	2013
Long Term Debt Range Adjusted To Fair Value At Merger End	2061
Unrealized gains / (losses) on financial instruments, Amount before tax	$ 1.2	$ 0.7
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax	0.8	0.5
Percent of inputs to the fair value of derivative instruments from quoted market prices	99.00%
Money market funds	175.0	130.0
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds	0.1
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax	0.1
DP&L [Member]
Long Term Debt Range Adjusted To Fair Value at Merger Start	2013
Long Term Debt Range Adjusted To Fair Value At Merger End	2061
Unrealized gains / (losses) on financial instruments, Amount before tax	2.1	1.6
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax	1.4	1.0
Percent of inputs to the fair value of derivative instruments from quoted market prices	99.00%
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds	0.1
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax	$ 0.1

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Supplemental Financial Information (Tables)

3 Months Ended

Mar. 31, 2013

Schedule of Supplemental Financial Information

	At		At
	March 31,		December 31,
$ in millions	2013		2012
Accounts receivable, net:
Unbilled revenue	$	65.3	$	75.2
Customer receivables		107.5		98.2
Amounts due from partners in jointly owned plants		15.3		19.7
Coal sales		-		1.6
Other		3.1		14.6
Provision for uncollectible accounts		(1.1)		(1.1)
Total accounts receivable, net	$	190.1	$	208.2
Inventories, at average cost:
Fuel and limestone	$	72.0	$	67.3
Plant materials and supplies		40.6		41.0
Other		1.9		1.8
Total inventories, at average cost	$	114.5	$	110.1

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

$ in millions	Gains / (losses) on Available-for-sale securities		Gains / (losses) on Cash Flow Hedges		Change in Unfunded Pension Obligation		Total
Balance January 1, 2013	$	0.4	$	(2.5)	$	(1.8)	$	(3.9)
Other comprehensive income before reclassifications		0.2		1.2		-		1.4
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1		0.2		0.3		0.6
Net current period other comprehensive income		0.3		1.4		0.3		2.0
Balance March 31, 2013	$	0.7	$	(1.1)	$	(1.5)	$	(1.9)

Reclassification out of Accumulated Other Comprehensive Income

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statement of Operations	Three months ended March 31,
$ in millions		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.1
	Total before income taxes		0.1
	Tax expense		-
	Net of income taxes		0.1
Gains and losses on cash flow hedges: (Note 9)
	Revenue		(0.5)
	Purchased power		0.8
	Total before income taxes		0.3
	Tax expense		(0.1)
	Net of income taxes		0.2
Amortization of defined benefit pension items: (Note 7)
	Reclassification to Other income / (deductions)		-
	Prior service cost for the period (1)		-
	Net loss for the period (1)		-
	Total before income taxes		-
	Tax benefit		0.3
	Net of income taxes		0.3
Total reclassifications for the period, net of income taxes		$	0.6

DP&L [Member]

Schedule of Supplemental Financial Information

	At		At
	March 31,		December 31,
$ in millions	2013		2012
Accounts receivable, net:
Unbilled revenue	$	41.6	$	48.1
Customer receivables		68.3		62.0
Amounts due from partners in jointly owned plants		15.3		19.7
Coal sales		-		1.6
Other		24.0		29.5
Provision for uncollectible accounts		(1.0)		(0.9)
Total accounts receivable, net	$	148.2	$	160.0
Inventories, at average cost:
Fuel and limestone	$	71.9	$	67.3
Plant materials and supplies		39.4		39.8
Other		1.9		1.8
Total inventories, at average cost	$	113.2	$	108.9

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

$ in millions	Gains / (losses) on Available-for-sale securities		Gains / (losses) on Cash Flow Hedges		Change in Unfunded Pension Obligation		Total
Balance January 1, 2013	$	1.0	$	2.6	$	(42.3)	$	(38.7)
Other comprehensive income / (loss) before reclassifications		0.2		(2.6)		0.9		(1.5)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.1		(0.2)		-		(0.1)
Net current period other comprehensive income / (loss)		0.3		(2.8)		0.9		(1.6)
Balance March 31, 2013	$	1.3	$	(0.2)	$	(41.4)	$	(40.3)

Reclassification out of Accumulated Other Comprehensive Income

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statement of Operations	Three months ended March 31,
$ in millions		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.2
	Total before income taxes		0.2
	Tax expense		(0.1)
	Net of income taxes		0.1
Gains and losses on cash flow hedges: (Note 9)
	Interest expense		(0.6)
	Revenue		(0.5)
	Purchased power		1.1
	Total before income taxes		-
	Tax expense		(0.2)
	Net of income taxes		(0.2)
Total reclassifications for the period, net of income taxes		$	(0.1)

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Pension and Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Net Periodic Benefit Cost / (Income)

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended March 31,		Three months ended March 31,		Three months ended March 31,		Three months ended March 31,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	0.1	$	0.1
Interest cost		3.9		4.3		0.2		0.3
Expected return on assets (a)		(5.9)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		1.2		1.2		(0.1)		(0.2)
Prior service cost		0.4		0.4		-		-
Net periodic benefit cost / (income)	$	1.4	$	1.7	$	0.1	$	0.1

Estimated Future Benefit Payments and Medicare Part D Reimbursements

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
2013	$	16.6	$	1.7
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		124.4		6.8

DP&L [Member]

Net Periodic Benefit Cost / (Income)

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended March 31,		Three months ended March 31,		Three months ended March 31,		Three months ended March 31,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	0.1	$	0.1
Interest cost		3.9		4.3		0.2		0.3
Expected return on assets (a)		(5.9)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		2.3		2.7		(0.1)		(0.2)
Prior service cost		0.7		0.8		-		-
Net periodic benefit cost / (income)	$	2.8	$	3.6	$	0.1	$	0.1

Estimated Future Benefit Payments and Medicare Part D Reimbursements

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
2013	$	16.6	$	1.7
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		124.4		6.8

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Pension and Postretirement Benefits (Net Periodic Benefit Cost (Income)) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Period in which the difference between market related value of assets is calculated in years, max	five
Period in which the difference between actual and estimated asset returns in MRVA is calculated	three
Market related value of assets	$ 346.0		$ 336.0
Pension [Member]
Service cost	1.8		1.5
Interest cost	3.9		4.3
Expected return on assets	(5.9)	[1]	(5.7)	[1]
Actuarial (gain) / loss	1.2		1.2
Prior service cost	0.4		0.4
Net periodic benefit cost / (income)	1.4		1.7
Postretirement [Member]
Service cost	0.1		0.1
Interest cost	0.2		0.3
Expected return on assets	(0.1)	[1]	(0.1)	[1]
Actuarial (gain) / loss	(0.1)		(0.2)
Net periodic benefit cost / (income)	0.1		0.1
DP&L [Member]
Market related value of assets	346.0		335.0
DP&L [Member] | Pension [Member]
Service cost	1.8		1.5
Interest cost	3.9		4.3
Expected return on assets	(5.9)	[1]	(5.7)	[1]
Actuarial (gain) / loss	2.3		2.7
Prior service cost	0.7		0.8
Net periodic benefit cost / (income)	2.8		3.6
DP&L [Member] | Postretirement [Member]
Service cost	0.1		0.1
Interest cost	0.2		0.3
Expected return on assets	(0.1)	[1]	(0.1)	[1]
Actuarial (gain) / loss	(0.1)		(0.2)
Net periodic benefit cost / (income)	$ 0.1		$ 0.1

[1] (a) For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $336.0 million, respectively. Benefit payments, which reflect future service, are expected to be paid as follows:Estimated Future Benefit Payments and Medicare Part D Reimbursements$ in millionsPensionPostretirement2013$ 16.6$ 1.72014 22.5 2.22015 23.0 2.02016 23.3 1.92017 23.7 1.72018 - 2022 124.4 6.8

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Ownership of Coal-fired Facilities (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013
Construction work in process	$ 39,000,000
Number Of Generating Facilities	7
DP&L [Member]
Construction work in process	31,000,000
Number Of Generating Facilities	7
Hutchings Plant [Member]
Undivided ownership interests	100.00%
Hutchings Plant [Member] | DP&L [Member]
Undivided ownership interests	100.00%
Beckjord Unit 6 [Member]
Undivided ownership interests	50.00%
Property, Plant, and Equipment, Fair Value Disclosure	$ 0
Beckjord Unit 6 [Member] | DP&L [Member]
Undivided ownership interests	50.00%

XML

Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash flows from operating activities:
Net income	$ 19.9	$ 21.7
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	31.8	31.4
Amortization of intangibles	1.8	27.8
Amortization of debt market value adjustments	(4.8)	(4.7)
Deferred income taxes	23.3	(9.2)
Changes in certain assets and liabilities:
Accounts receivable	19.5	(3.4)
Inventories	(4.4)	(0.6)
Taxes applicable to subsequent years	17.2	22.9
Deferred regulatory costs, net	3.6	7.2
Accounts payable	2.7	(1.8)
Accrued taxes payable	(33.7)	(21.6)
Accrued interest payable	23.7	29.1
Pension, retiree and other benefits	3.2	2.1
Insurance and claims costs	1.0	0.8
Other	1.4	2.3
Net cash provided by operating activities	106.2	104.0
Cash flows from investing activities:
Capital expenditures	(33.8)	(54.0)
Increase (Decrease) in Restricted Cash	(12.7)	(8.7)
Net cash used for investing activities	(47.0)	(63.4)
Cash flows from financing activities:
Dividends paid on common stock		(45.0)
Payment to former warrant holders		(9.0)
Contributions to additional paid-in capital from parent		2.0
Net cash used for financing activities		(52.0)
Cash and cash equivalents:
Net change	59.2	(11.4)
Balance at beginning of period	192.1	173.5
Cash and cash equivalents at end of period	251.3	162.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	11.3	5.7
Income taxes paid/(refund), net	(20.0)	7.0
Non-cash financing and investing activities:
Accruals for capital expenditures	10.6	24.1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from operating activities:
Net income	30.2	38.1
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	33.6	34.7
Deferred income taxes	22.9	(2.4)
Changes in certain assets and liabilities:
Accounts receivable	13.2	(0.6)
Inventories	(4.3)	(2.0)
Taxes applicable to subsequent years	16.7	21.5
Deferred regulatory costs, net	3.6	7.1
Accounts payable	2.7	(2.2)
Accrued taxes payable	(25.3)	(15.0)
Accrued interest payable	2.3	7.5
Pension, retiree and other benefits	3.2	2.1
Unamortized investment tax credit	(0.6)	(0.6)
Other	3.6	10.8
Net cash provided by operating activities	101.8	99.0
Cash flows from investing activities:
Capital expenditures	(33.6)	(53.2)
Increase (Decrease) in Restricted Cash	(12.7)	(8.7)
Net cash used for investing activities	(46.8)	(62.6)
Cash flows from financing activities:
Dividends paid on common stock	(55.0)	(45.0)
Dividends paid on preferred stock	(0.2)	(0.2)
Net cash used for financing activities	(55.2)	(45.2)
Cash and cash equivalents:
Net change	(0.2)	(8.8)
Balance at beginning of period	28.5	32.2
Cash and cash equivalents at end of period	28.3	23.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	7.9	2.4
Income taxes paid/(refund), net	(20.0)	6.1
Non-cash financing and investing activities:
Accruals for capital expenditures	10.6	24.1
Renewable Energy Certificates [Member]
Cash flows from investing activities:
Payments to Acquire Intangible Assets	(0.5)	(0.7)
Renewable Energy Certificates [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from investing activities:
Payments to Acquire Intangible Assets	$ (0.5)	$ (0.7)

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Ownership of Coal-fired Facilities

3 Months Ended

Mar. 31, 2013

Ownership of Coal-fired Facilities

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities with certain other Ohio utilities.  Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on the energy taken.  The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  As of March 31, 2013,  DP&L had $39.0 million of construction work in process at such jointly owned facilities.  DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets.  Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned units and stations. 

DP&L’s undivided ownership interest in such facilities as well as our wholly owned coal-fired Hutchings Station at March 31, 2013 is as follows: 

	DP&L Share			DP&L Investment
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)	Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Beckjord Unit 6	50.0	207	$	1	$	1	$	-	No
Conesville Unit 4	16.5	129		42		4		12	Yes
East Bend Station	31.0	186		8		3		3	Yes
Killen Station	67.0	402		301		4		9	Yes
Miami Fort Units 7 and 8	36.0	368		212		9		3	Yes
Stuart Station	35.0	808		202		7		10	Yes
Zimmer Station	28.1	365		169		15		2	Yes
Transmission (at varying percentages)		n/a		40		2		-
Total		2,465	$	975	$	45	$	39
Wholly owned production station:
Hutchings Station	100.0	365	$	-	$	-	$	-	No

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

DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated on June 1, 2013.  In addition, DP&L has notified PJM that the remaining coal-fired units at Hutchings Station will be deactivated on June 1, 2015.  The decision to deactivate these remaining coal-fired units has been made because these units are not equipped with the advanced environmental control technologies needed to comply with the MATS, and the expected cost of compliance with MATS for these units would exceed the expected return.  Additionally, conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return.

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

DP&L [Member]

Ownership of Coal-fired Facilities

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities with certain other Ohio utilities.  Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on the energy taken.  The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  As of March 31, 2013,  DP&L had $31.0 million of construction work in process at such jointly owned facilities.  DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.  Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned unit or station. 

DP&L’s undivided ownership interest in such facilities as well as our wholly owned coal-fired Hutchings Station at March 31, 2013, is as follows: 

	DP&L Share			DP&L Investment
Jointly owned production units and stations:	Ownership (%)	Summer Production Capacity (MW)	Gross Plant in Service ($ in millions)		Accumulated Depreciation ($ in millions)		Construction Work in Process ($ in millions)		SCR and FGD Equipment Installed and in Service (Yes/No)
Beckjord Unit 6	50.0	207	$	76	$	64	$	-	No
Conesville Unit 4	16.5	129		28		2		4	Yes
East Bend Station	31.0	186		209		137		3	Yes
Killen Station	67.0	402		617		302		9	Yes
Miami Fort Units 7 and 8	36.0	368		361		148		3	Yes
Stuart Station	35.0	808		744		297		10	Yes
Zimmer Station	28.1	365		1,097		644		2	Yes
Transmission (at varying percentages)				97		59		-
Total		2,465	$	3,229	$	1,653	$	31
Wholly owned production station:
Hutchings Station	100.0	365	$	-	$	-	$	-	No

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

DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated on June 1, 2013.  In addition, DP&L has notified PJM that the remaining coal-fired units at Hutchings Station will be deactivated on June 1, 2015.  The decision to deactivate these remaining coal-fired units has been made because these units are not equipped with the advanced environmental control technologies needed to comply with the MATS, and the expected cost of compliance with MATS for these units would exceed the expected return.  Additionally, conversion of the coal-fired units to natural gas was investigated, but the cost of investment exceeded the expected return.

As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a zero fair market value.  Since DP&L did not apply push down accounting, this valuation did not affect the book value of these stations’ or units’ valuation at DP&L.

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Derivative Instruments and Hedging Activities (Fair Values of Derivative Instruments Designated as Hedging Instruments) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
DP&L [Member]
Derivative Liability, Fair Value	$ (22.9)
Not Designated as Hedging Instrument [Member]
Derivative Liability, Fair Value	(23.3)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	4.5	2.7
Derivative, Fair Value, Net	0.7	1.2
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member] | DP&L [Member]
Derivative Asset, Fair Value	5.3	2.8
Derivative, Fair Value, Net	1.5	1.3
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	(9.9)	(4.1)
Derivative, Fair Value, Net	0.6	0.6
Derivative, Collateral, net	(5.5)	(2.0)
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member] | DP&L [Member]
Derivative Liability, Fair Value	(9.5)	(2.7)
Derivative, Fair Value, Net	0.6	0.7
Derivative, Collateral, net	(5.1)	(0.5)
Derivative, Fair Value, Offset, Net	(3.8)	(1.5)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value	(2.6)	(0.8)
Derivative, Fair Value, Net	0.5	0.1
Derivative, Collateral, net	(1.5)	(0.1)
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member] | DP&L [Member]
Derivative Liability, Fair Value	(2.6)	(0.7)
Derivative, Fair Value, Net	0.5	0.1
Derivative, Collateral, net	(1.5)
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	1.1	3.6
Derivative, Fair Value, Net	0.5	3.0
Derivative, Fair Value, Offset, Net	(0.6)	(0.6)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member] | DP&L [Member]
Derivative Asset, Fair Value	1.1	3.6
Derivative, Fair Value, Net	0.5	3.0
Derivative, Fair Value, Offset, Net	$ (0.6)	$ (0.6)

XML

Fair Value Measurements (Tables)

3 Months Ended

12 Months Ended

15 Months Ended

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2013

Fair Value and Cost of Non-Derivative Instruments

	At March 31,				At December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities		4.0		5.7		4.0		5.1
Debt Securities		4.5		4.9		4.6		5.0
Multi-Strategy Fund		0.3		0.3		0.3		0.3
Total Assets	$	9.0	$	11.1	$	9.1	$	10.6
Liabilities
Debt	$	2,605.1	$	2,705.4	$	2,609.9	$	2,707.1

Fair Value and Redemption Frequency

Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at March 31, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	-	Immediate
Equity Securities (b)		5.7		5.1		-	Immediate
Debt Securities (c)		4.9		5.0		-	Immediate
Multi-Strategy Fund (d)		0.3		0.3		-	Immediate
Total	$	11.1	$	10.6	$	-

Fair Value of Assets and Liabilities Measured on Recurring Basis

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.7		-		5.7		-
Debt Securities		4.9		-		4.9		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		11.1		0.2		10.9		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		5.8		-		5.8		-
Total Derivative Assets		6.0		0.2		5.8		-
Total Assets	$	17.1	$	0.4	$	16.7	$	-
Liabilities
Derivative Liabilities
Interest Rate Hedge	$	23.2	$	-	$	23.2	$	-
Forward Power Contracts		23.3		-		23.3		-
Total Derivative Liabilities		46.5		-		46.5		-
Long-term Debt		2,705.4		-		2,686.6		18.8
Total Liabilities	$	2,751.9	$	-	$	2,733.1	$	18.8

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.3		-		6.3		-
Total Derivative Assets		6.5		0.2		6.3		-
Total Assets	$	17.1	$	0.4	$	16.7	$	-
Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Interest Rate Hedge		29.5		-		29.5		-
Forward Power Contracts		13.1		-		13.1		-
Total Derivative Liabilities		42.7		-		42.6		0.1
Long-term debt		2,707.1		-		2,688.2		18.9
Total Liabilities	$	2,749.8	$	-	$	2,730.8	$	19.0

DP&L [Member]

Fair Value and Cost of Non-Derivative Instruments

	At March 31,				At December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities		4.0		5.7		4.0		5.1
Debt Securities		4.5		4.9		4.6		5.0
Multi-Strategy Fund		0.3		0.3		0.3		0.3
Total Assets	$	9.0	$	11.1	$	9.1	$	10.6
Liabilities
Debt	$	903.1	$	921.8	$	903.1	$	926.9

Fair Value and Redemption Frequency

Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at March 31, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	-	Immediate
Equity Securities (b)		5.7		5.1		-	Immediate
Debt Securities (c)		4.9		5.0		-	Immediate
Multi-Strategy Fund (d)		0.3		0.3		-	Immediate
Total	$	11.1	$	10.6	$	-

Fair Value of Assets and Liabilities Measured on Recurring Basis

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.7		-		5.7		-
Debt Securities		4.9		-		4.9		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		11.1		0.2		10.9		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.6		-		6.6		-
Total Derivative Assets		6.8		0.2		6.6		-
Total Assets	$	17.9	$	0.4	$	17.5	$	-
Liabilities
Derivative Liabilities
Forward Power Contracts	$	22.9	$	-	$	22.9	$	-
Total Derivative Liabilities		22.9		-		22.9		-
Long-term Debt		921.8		-		903.0		18.8
Total Liabilities	$	944.7	$	-	$	925.9	$	18.8

Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-
Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		7.3		-		7.3		-
Total Derivative Assets		7.5		0.2		7.3		-
Total Assets	$	18.1	$	0.4	$	17.7	$	-
Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Forward Power Contracts		11.6		-		11.6		-
Total Derivative Liabilities		11.7		-		11.6		0.1
Long-term debt		926.9		-		908.0		18.9
Total Liabilities	$	938.6	$	-	$	919.6	$	19.0

XML

Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Total Reclassifications out of AOCI	$ 0.6
Total Adjustments to AOCI	1.4
Other Comprehensive Income (Loss), Net of Tax	2.0	7.1
Accumulated Other Comprehensive Income (Loss), Net of Tax	(1.9)		(3.9)
DP&L [Member]
Total Reclassifications out of AOCI	(0.1)
Total Adjustments to AOCI	(1.5)
Other Comprehensive Income (Loss), Net of Tax	(1.6)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(40.3)		(38.7)
Available-for-sale Securities [Member]
Total Reclassifications out of AOCI	0.1
Total Adjustments to AOCI	0.2
Other Comprehensive Income (Loss), Net of Tax	0.3
Accumulated Other Comprehensive Income (Loss), Net of Tax	0.7		0.4
Available-for-sale Securities [Member] | DP&L [Member]
Total Reclassifications out of AOCI	0.1
Total Adjustments to AOCI	0.2
Other Comprehensive Income (Loss), Net of Tax	0.3
Accumulated Other Comprehensive Income (Loss), Net of Tax	1.3		1.0
Derivative [Member]
Total Reclassifications out of AOCI	0.2
Total Adjustments to AOCI	1.2
Other Comprehensive Income (Loss), Net of Tax	1.4
Accumulated Other Comprehensive Income (Loss), Net of Tax	(1.1)		(2.5)
Derivative [Member] | DP&L [Member]
Total Reclassifications out of AOCI	(0.2)
Total Adjustments to AOCI	(2.6)
Other Comprehensive Income (Loss), Net of Tax	(2.8)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(0.2)		2.6
Other Pension Plans, Defined Benefit [Member]
Total Reclassifications out of AOCI	0.3
Other Comprehensive Income (Loss), Net of Tax	0.3
Accumulated Other Comprehensive Income (Loss), Net of Tax	(1.5)		(1.8)
Other Pension Plans, Defined Benefit [Member] | DP&L [Member]
Total Adjustments to AOCI	0.9
Other Comprehensive Income (Loss), Net of Tax	0.9
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (41.4)		$ (42.3)

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2013

Overview and Summary of Significant Accounting Policies [Abstract]

Related Party Transactions

	Three months ended
	March 31,
	2013		2012
DP&L Revenues:
Sales to DPLER (a)	$	78.7	$	83.0
Sales to MC Squared	$	25.6	$	-
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.6)
Expense recoveries for services provided to DPLER (c)	$	1.1	$	0.9
DP&L Customer security deposits:
Deposits received from DPLER (d)	$	19.2	$	-