10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(x) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

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 ☐	No ☒
The Dayton Power and Light Company	Yes ☒	No ☐

DPL Inc. is a voluntary filer that has 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 ☒	No ☐
The Dayton Power and Light Company	Yes ☒	No ☐

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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.	☐	☐	☒	☐
The Dayton Power and Light Company	☐	☐	☒	☐

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

DPL Inc.	Yes ☐	No ☒
The Dayton Power and Light Company	Yes ☐	No ☒

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 September 30, 2014, 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

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
Table of Contents Quarterly Report on Form 10-Q
Quarter Ended September 30, 2014
		Page No.
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 Results of Operations	13
	Condensed Consolidated Statements of Comprehensive Income  / (Loss)	14
	Condensed Consolidated Statements of Cash Flows	15
	Condensed Consolidated Balance Sheets	17
	Notes to Condensed Consolidated Financial Statements	19
	The Dayton Power and Light Company
	Condensed Statements of Results of Operations	48
	Condensed Statements of Comprehensive Income  / (Loss)	49
	Condensed Statements of Cash Flows	50
	Condensed Balance Sheets	52
	Notes to Condensed Financial Statements	54
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	75
	Electric Sales and Revenues	103
Item 3	Quantitative and Qualitative Disclosures about Market Risk	103
Item 4	Controls and Procedures	103

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DPL Inc. and The Dayton Power and Light Company
Index to Quarterly Report on Form 10-Q (cont.)
Quarter Ended September 30, 2014
		Page No.
Part II  Other Information
Item 1	Legal Proceedings	104
Item 1A	Risk Factors	104
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	105
Item 3	Defaults Upon Senior Securities	105
Item 4	Mine Safety Disclosures	105
Item 5	Other Information	105
Item 6	Exhibits	106
Other
Signatures		108

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GLOSSARY OF TERMS 

The following terms are used in this Form 10-Q: 

Term	Definition
AEP Generation	AEP Generation Resources Inc., 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.  The Ohio Power generating assets (including jointly-owned units) were transferred into this new AEP subsidiary, effective January 1, 2014.
AER	Alternative Energy Rider allows DP&L to recover costs related to meeting the Ohio renewable portfolio standards.
AES	The AES Corporation, a global power company and the ultimate parent company of DPL
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
BTU	British Thermal Units
CAA	Clean Air Act
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
CWA	Clean Water Act
Dark spread	A common metric used to estimate returns over fuel costs of coal-fired electric generating units
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 that 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 that delivers 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
ERISA	The Employee Retirement Income Security Act of 1974
ESP	Electric Security Plans filed with the PUCO, pursuant to Ohio law
ESSS	PUCO Electric Service and Safety Standards
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification

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GLOSSARY OF TERMS (cont.)
Term	Definition
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
Form 10-K	DPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, 2013, which was filed on March 4, 2014
First and Refunding Mortgage	DP&L’s First and Refunding Mortgage, dated October 1, 1935, as amended, with the Bank of New York Mellon as Trustee
FTR	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
IFRS	International Financial Reporting Standards
kV	Kilovolts, 1,000 volts
kWh	Kilowatt hours
LIBOR	London Inter-Bank Offering Rate
Master Trusts	DP&L established Master Trusts 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
MW	Megawatt
MWh	Megawatt hour
NERC	North American Electric Reliability Corporation
Non-bypassable	Charges that are assessed to all customers regardless of whom the customer selects as their retail electric generation supplier
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System

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GLOSSARY OF TERMS (cont.)
Term	Definition
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
OCC	Ohio Consumers’ Counsel
OCI	Other Comprehensive Income
Ohio EPA	Ohio Environmental Protection Agency
OTC	Over-The-Counter
OVEC	Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest
PJM	PJM Interconnection, LLC, an RTO
PPM	Parts Per Million
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
ROE	Return on equity
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
SEET	Significantly Excessive Earnings Test
SERP	Supplemental Executive Retirement Plan
Service Company	AES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses
SFAS	Statement of Financial Accounting Standards
SIP	AState Implementation Planis aplan for complying with the federalCAA, administered by the USEPA. The SIP consists of narrative, rules, technical documentation and agreements that an individual state will use to clean up polluted areas.

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GLOSSARY OF TERMS (cont.)
Term	Definition
SO2	Sulfur Dioxide
SO3	Sulfur Trioxide
SSO	Standard Service Offer represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers that take retail generation service from DP&L within DP&L’s service territory
SSR	Service Stability Rider
TCRR	Transmission Cost Recovery Rider
TCRR-B	Transmission Cost Recovery Rider – Bypassable
TCRR-N	Transmission Cost Recovery Rider – Non-bypassable
USEPA	U.S. Environmental Protection Agency
USF	The Universal Service Fund (USF) is a statewide program which provides qualified low-income customers in Ohio with income-based bills and energy efficiency education programs
U.S. SBU	U. S. Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL
VRDN	Variable Rate Demand Note

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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, 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 emission allowances, natural gas and other commodity prices;

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

· performance of our suppliers;

· increased competition and deregulation in the electric utility industry;

· increased competition in the retail generation market;

· availability and price of capacity;

· changes in interest rates;

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

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

· the operation of RTOs, including PJM to which DPL’s operating subsidiary (DP&L) has given control of its transmission functions;

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

· significant delays associated with large construction projects;

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

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

· financial market conditions;

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

· general economic conditions; and

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

Forward-looking statements speak only as of the date of the document in which they are made.  We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based.  If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

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

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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 www.sec.gov.

COMPANY WEBSITES

DPL’s public internet site is www.dplinc.com.  DP&L’s public internet site is 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 applicable section.

Item 1 – Financial Statements

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FINANCIAL STATEMENTS

DPL INC.

12

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS
	Three months ended September 30,				Nine months ended September 30,
$ in millions	2014		2013		2014		2013
Revenues	$	479.2	$	441.2	$	1,329.6	$	1,210.7
Cost of revenues:
Fuel		85.1		99.7		235.9		274.0
Purchased power		153.7		113.1		466.2		282.6
Amortization of intangibles		0.3		1.8		0.9		5.3
Total cost of revenues		239.1		214.6		703.0		561.9
Gross margin		240.1		226.6		626.6		648.8
Operating expenses:
Operation and maintenance		94.0		97.3		294.7		297.4
Depreciation and amortization		34.5		33.9		103.7		99.0
General taxes		21.2		19.4		70.3		60.8
Goodwill impairment		-		-		135.8		-
Fixed-asset impairment		-		-		11.5		-
Total operating expenses		149.7		150.6		616.0		457.2
Operating income		90.4		76.0		10.6		191.6
Other income / (expense), net:
Investment income / (loss)		0.2		(0.5)		0.6		1.2
Interest expense		(33.1)		(31.0)		(95.8)		(91.1)
Other income / (expense)		(0.1)		-		(2.5)		(4.9)
Total other expense		(33.0)		(31.5)		(97.7)		(94.8)
Earnings / (loss) before income taxes		57.4		44.5		(87.1)		96.8
Income tax expense / (benefit)		(41.0)		11.3		29.7		20.8
Net income / (loss)	$	98.4	$	33.2	$	(116.8)	$	76.0
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

13

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
	Three months ended September 30,				Nine months ended September 30,
$ in millions	2014		2013		2014		2013
Net income / (loss)	$	98.4	$	33.2	$	(116.8)	$	76.0
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $0.2, $(0.1), $0.2 and $0.7 for each respective period		(0.4)		0.2		(0.6)		(1.3)
Reclassification to earnings, net of income tax expense of $(0.1), $(0.2), $(0.2) and $(0.7) for each respective period		0.2		0.4		0.4		1.4
Total change in fair value of available-for-sale securities		(0.2)		0.6		(0.2)		0.1
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(1.0), $(3.3), $12.4 and $(10.0) for each respective period		1.2		6.2		(23.8)		18.7
Reclassification to earnings, net of income tax expense of $(1.5), $(0.8), $(7.4) and $(2.1) for each respective period		3.4		1.3		14.2		3.0
Total change in fair value of derivatives		4.6		7.5		(9.6)		21.7
Pension and postretirement activity:
Reclassification to earnings, net of income tax benefit of $0.0, $0.0, $0.0 and $0.3 for each respective period		-		-		-		0.3
Total change in unfunded pension obligation		-		-		-		0.3
Other comprehensive income / (loss)		4.4		8.1		(9.8)		22.1
Net comprehensive income / (loss)	$	102.8	$	41.3	$	(126.6)	$	98.1
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

14

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine months ended September 30,
$ in millions	2014		2013
Cash flows from operating activities:
Net income / (loss)	$	(116.8)	$	76.0
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization		103.7		99.0
Amortization of intangibles		0.9		5.3
Amortization of debt market value adjustments		0.1		(14.3)
Deferred income taxes		(2.5)		31.5
Goodwill Impairment		135.8		-
Fixed-asset impairment		11.5		-
Changes in certain assets and liabilities:
Accounts receivable		12.7		30.8
Inventories		(3.6)		18.6
Prepaid taxes		0.5		0.7
Taxes applicable to subsequent years		52.1		52.1
Deferred regulatory costs, net		4.8		11.6
Accounts payable		7.2		(7.2)
Accrued taxes payable		(27.5)		(69.3)
Accrued interest payable		14.5		24.3
Pension, retiree and other benefits		(5.2)		7.1
Unamortized investment tax credit		(0.4)		(0.4)
Insurance and claims costs		0.4		(2.4)
Other		(13.8)		(14.3)
Net cash from operating activities		174.4		249.1
Cash flows from investing activities:
Capital expenditures		(81.6)		(96.5)
Purchase of emission allowances		(0.2)		-
Purchase of renewable energy credits		(3.4)		(3.3)
Decrease / (increase) in restricted cash		(9.0)		3.4
Insurance proceeds		-		7.6
Proceeds from sale of property		-		0.8
Other investing activities, net		1.1		(1.6)
Net cash from investing activities		(93.1)		(89.6)

15

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (cont.)
	Nine months ended September 30,
$ in millions	2014		2013
Net cash from financing activities:
Issuance of long-term debt, net		-		644.2
Deferred finance costs		(0.3)		(11.6)
Borrowings from revolving credit facilities		115.0		50.0
Repayment of borrowings from revolving credit facilities		(115.0)		(50.0)
Retirement of long-term debt		(30.1)		(425.1)
Net cash from financing activities		(30.4)		207.5
Cash and cash equivalents:
Net change		50.9		367.0
Balance at beginning of period		53.2		192.1
Cash and cash equivalents at end of period	$	104.1	$	559.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	73.8	$	79.5
Income taxes paid / (refunded), net	$	0.2	$	(20.2)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	6.7	$	5.4
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

16

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
$ in millions	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	104.1	$	53.2
Restricted cash		22.5		13.5
Accounts receivable, net (Note 2)		190.7		203.3
Inventories (Note 2)		86.4		82.7
Taxes applicable to subsequent years		18.5		70.6
Regulatory assets, current (Note 3)		30.0		20.8
Other prepayments and current assets		44.9		35.1
Total current assets		497.1		479.2
Property, plant & equipment:
Property, plant & equipment		2,724.1		2,677.0
Less: Accumulated depreciation and amortization		(288.5)		(206.7)
		2,435.6		2,470.3
Construction work in process		65.8		63.9
Total net property, plant & equipment		2,501.4		2,534.2
Other non-current assets:
Regulatory assets, non-current (Note 3)		147.8		159.7
Goodwill		317.0		452.8
Intangible assets, net of amortization		38.6		42.8
Other deferred assets		40.7		52.8
Total other non-current assets		544.1		708.1
Total assets	$	3,542.6	$	3,721.5
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

17

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
$ in millions	2014		2013
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 5)	$	110.1	$	10.2
Accounts payable		77.4		78.2
Accrued taxes		131.9		89.4
Accrued interest		43.2		28.5
Customer security deposits		14.4		13.9
Regulatory liabilities, current		10.0		-
Insurance and claims costs		7.0		6.7
Other current liabilities		66.3		64.2
Total current liabilities		460.3		291.1
Non-current liabilities:
Long-term debt (Note 5)		2,154.3		2,284.2
Deferred taxes		553.4		564.3
Taxes payable		3.0		79.1
Regulatory liabilities, non-current		123.7		121.1
Pension, retiree and other benefits		42.7		51.6
Unamortized investment tax credit		2.4		2.8
Other deferred credits		71.0		69.4
Total non-current liabilities		2,950.5		3,172.5
Redeemable preferred stock of subsidiary		18.4		18.4
Commitments and contingencies (Note 10)
Common shareholder's equity:
Common stock, including Other paid-in capital:
1,500 shares authorized; 1 share issued and outstanding at September 30, 2014 and December 31, 2013		2,237.5		2,237.0
Accumulated other comprehensive income		14.8		24.6
Accumulated deficit		(2,138.9)		(2,022.1)
Total common shareholder's equity		113.4		239.5
Total liabilities and shareholder's equity	$	3,542.6	$	3,721.5
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.  The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES.  Following the Merger, DPL became an indirectly wholly owned subsidiary of AES.

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated.  DP&L has the exclusive right to provide such distribution and transmission services to its more than 515,000 customers located in West Central Ohio.  Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense.  DP&L's sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity.  DP&L sells any excess energy and capacity into the wholesale market.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

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.  DPLER has approximately 274,000 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 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 our subsidiaries and us.  DPLowns all of the common stock of its subsidiaries. 

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 1,197 people as of September 30, 2014, of which 1,142 were employed by DP&L.  Approximately 61% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.The current collective bargaining agreement was ratified by the membership on October 30, 2014.

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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 has undivided ownership interests in seven coal-fired and peaking generating facilities as well as numerous transmission facilities,all of which 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 Statements of Results 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, 2013. 

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 September 30, 2014; our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013.  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 EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014. 

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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles. 

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value.

Goodwill Impairment

In connection with the Merger, DPL re-measured 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.  DPL’s annual testing date for goodwill is October 1 of each year.  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 certain events, 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 

DPLER sells receivables from its customers in Duke Energy’s territory to Duke Energy.  Receivables sold to Duke Energy during the three months ended September 30, 2014 and 2013 were $10.6 million and $6.1 million,

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respectively.  Receivables sold to Duke Energy during the nine months ended September 30, 2014 and 2013 were $30.4 million and $15.6 million, respectively.  Similarly, MC Squared sells receivables from its customers in ComEd territory to ComEd.  Receivables sold to ComEd during the three months ended September 30, 2014 and 2013 were $27.1 million and $22.6 million, respectively.  Receivables sold to ComEd during the nine months ended September 30, 2014 and 2013 were $68.3 million and $57.8 million, respectively.  There is no recourse or any other continuing involvement associated with the sold receivables.These sales are at face value for cash at the amounts billed for DPLER or MC Squared customers’ use of energy. 

Regulatory Accounting

As a regulated utility, DP&L applies the provisions of FASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory assets can also represent performance incentives permitted by the regulator, such as with our Energy Efficiency Shared Savings.  Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices.  Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DPL expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable.  In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment.  To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.  Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs.  It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval.  Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.  See Note 3 for more information about Regulatory Assets.

Property, Plant & 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 except for adjustments of generating plants to fair market value recorded in connection with the Merger, subsequent impairments and the adjustment of certain intangible assets to fair market value in connection with the 2011 acquisition of MC Squared by DPLER. 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. 

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 and customer contracts.  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 and nine months ended September 30, 2014 and 2013, gains from the sale of emission allowances were immaterial. 

Customer relationships recognized as part of the purchase accounting associated with the Merger are amortized over ten to seventeen years and customer contracts were amortized over the average length of the contracts.  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. 

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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 not included in revenue.  The amounts of such taxes collected for the three months ended September 30, 2014 and 2013 were $12.5 million and $13.0 million, respectively.  The amounts of such taxes collected for theninemonths ended September 30, 2014 and 2013 were $38.5 million and $38.0 million, respectively.

Related Party Transactions 

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L.  The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations.  This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Transactions with the Service Company
Charges for services provided	$	5.5	$	-	$	27.8	$	-
Charges to the Service Company		0.2		-		0.2		-

Transactions with the Service Company	At September 30, 2014		At December 31, 2013
Net prepaid / (payable) to the Service Company	$	9.4	$	-

DPL has issued debt to a wholly owned business trust, DPL Capital Trust II.

Recently Issued Accounting Standards

Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016.  ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.  There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.  This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application.  The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns.  Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.  We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

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Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” effective for annual and interim periods beginning after December 15, 2014.  ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results.  In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes.  For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes.  Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact on our overall results of operations, financial position or cash flows.

2. Supplemental Financial Information 

Accounts receivable and Inventories are as follows at September 30, 2014 and December 31, 2013:

	September 30,		December 31,
$ in millions	2014		2013
Accounts receivable, net:
Unbilled revenue	$	65.7	$	77.8
Customer receivables		112.9		102.7
Amounts due from partners in jointly owned plants		10.4		15.8
Other		3.0		8.2
Provision for uncollectible accounts		(1.3)		(1.2)
Total accounts receivable, net	$	190.7	$	203.3
Inventories, at average cost:
Fuel and limestone	$	48.5	$	42.7
Plant materials and supplies		36.2		38.2
Other		1.7		1.8
Total inventories, at average cost	$	86.4	$	82.7

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Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months endedSeptember 30, 2014 and 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended				Nine months ended
		September 30,				September 30,
$ in millions		2014		2013		2014		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income	$	0.3	$	0.6	$	0.6	$	2.1
	Tax expense		(0.1)		(0.2)		(0.2)		(0.7)
	Net of income taxes		0.2		0.4		0.4		1.4
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.3)		-		(1.0)		-
	Revenue		4.9		0.5		23.4		2.2
	Purchased power		0.3		1.6		(0.8)		2.9
	Total before income taxes		4.9		2.1		21.6		5.1
	Tax expense		(1.5)		(0.8)		(7.4)		(2.1)
	Net of income taxes		3.4		1.3		14.2		3.0
Amortization of defined benefit pension items (Note 7):
	Tax benefit		-		-		-		0.3
	Net of income taxes		-		-		-		0.3
Total reclassifications for the period, net of income taxes		$	3.6	$	1.7	$	14.6	$	4.7

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2014 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, 2014	$	0.6	$	20.6	$	3.4	$	24.6
Other comprehensive loss before reclassifications		(0.6)		(23.8)		-		(24.4)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.4		14.2		-		14.6
Net current period other comprehensive loss		(0.2)		(9.6)		-		(9.8)
Balance September 30, 2014	$	0.4	$	11.0	$	3.4	$	14.8

3.  Regulatory Assets 

DP&L’s regulatory asset for deferred storm costs represents costs incurred to repair the damage caused to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. Such costs are included in Regulatory assets, non-current on the accompanying Condensed Consolidated Balance Sheets and were $22.3 million and

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$25.6 million as of September 30, 2014 and December 31, 2013, respectively. DP&L filed an application with the PUCO in 2012 to recover these costs.  The main issue in the case was the level of storm costs that should be recoverable. On April 14, 2014, DP&L reached an agreement in principle with the PUCO Staff whereby DP&L would recover storm costs of $22.3 million from all customers on a non-bypassable basis.  As a result of these developments, we reduced the regulatory asset balance to $22.3 million as our best estimate of the amount that is probable of recovery.  In accordance with FASC 980 “Regulated Operations”, the reduction was recognized as a current period expense, which is included in Operation and maintenanceand the corresponding adjustment to carrying costs which is included in interest expense on the accompanying Condensed Consolidated Statements of Results of Operations.  A stipulation was finalized and filed at the PUCO and a hearing took place the first week of June 2014.  A decision is expected before the end of the year.

In August 2014, the PUCO issued an order in a case relating to review of DP&L’s fuel cost recovery mechanism for the calendar year 2012. The order included the disallowance of an immaterial amount of fuel costs. The impact of the order issued was a reversal in the third quarter of a previously established$2.6 million reserve.

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities, various peaking facilitiesand numerous transmission facilities with certain other Ohio utilities.  Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage.  The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  At September 30, 2014,  DP&L had  $19.0 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 at September 30, 2014 is as follows: 

	DP&L Share			DPL Carrying value
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	$	2	$	1	$	-	No
Conesville Unit 4	16.5	129		24		1		-	Yes
East Bend Station	31.0	186		-		-		-	Yes
Killen Station	67.0	402		309		17		2	Yes
Miami Fort Units 7 and 8	36.0	368		213		21		1	Yes
Stuart Station	35.0	808		213		15		12	Yes
Zimmer Station	28.1	365		181		33		4	Yes
Transmission (at varying percentages)		n/a		42		5		-
Total		2,465	$	984	$	93	$	19

Beckjord Unit 6, in which DP&L has a 50% ownership interest, is currently inoperable, and there are no plans to return it to service.  This unit was retired effective October 1, 2014.

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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As discussed in Note 13, we have reached an agreement to sell our interest in the East Bend station.

5.  Debt Obligations 

Long-term debt

	September 30,		December 31,
$ in millions	2014		2013
First mortgage bonds due in September 2016 - 1.875%	$	445.0	$	445.0
Pollution control series due in January 2028 - 4.7%		36.0		36.0
Pollution control series due in January 2034 - 4.8%		179.6		179.6
Pollution control series due in September 2036 - 4.8%		96.4		96.4
Pollution control series due in November 2040 - rates from: 0.04% - 0.15% and 0.05% - 0.24% (a)		100.0		100.0
U.S. Government note due in February 2061 - 4.2%		18.1		18.3
Unamortized debt discount		(0.5)		(0.7)
Total long-term debt at subsidiary		874.6		874.6
Bank term loan due in May 2018 - rates from: 2.41% - 2.42% and 2.42% - 2.45% (a)		150.0		180.0
Senior unsecured bonds due in October 2016 - 6.5%		330.0		430.0
Senior unsecured bonds due in October 2021 - 7.25%		780.0		780.0
Note to DPL Capital Trust II due in September 2031 - 8.125% (b)		19.7		19.6
Total non-current portion of long-term debt	$	2,154.3	$	2,284.2

Current portion of long-term debt 

	September 30,		December 31,
$ in millions	2014		2013
Bank term loan due in May 2018 - rates from: 2.41% - 2.42% and 2.42% - 2.45% (a)	$	10.0	$	10.0
Senior unsecured bonds due in October 2016 - 6.5%		100.0		-
U.S. Government note due in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		-		0.1
Total current portion of long-term debt	$	110.1	$	10.2

(a)Range of interest rates for the nine months ended September 30, 2014 and the twelve months ended December 31, 2013, respectively. 

(b)Note payable to related party. See Note 1: Related Party Transactions for additional information.

At September 30, 2014, maturities of long-term debt are as follows:

Due within the twelve months ending September 30,
($ in millions)
2015	$	110.1
2016		385.1
2017		470.1
2018		70.1
2019		0.1
Thereafter		1,232.7
Total maturities		2,268.2
Unamortized premiums and discounts		(3.8)
Total long-term debt	$	2,264.4

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

On May 10, 2013, DP&L closed a $300.0 million unsecured revolving credit agreement with a syndicated bank group. This $300.0 million facility has a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million.  At September 30, 2014, there were two letters of credit in the amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L.  Fees associated with this letter of credit facility were not material during the three and nine months ended September 30, 2014.

DP&L’s unsecured revolving credit agreement and DP&L’s amended standby letters of credit have two financial covenants, the first measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter.  The second financial covenant ratio compares 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.

On May 10, 2013, DPLentered into a $100.0 million unsecured revolving credit facility. This $100.0 million facility has a $100.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $50.0 million. This facility has a five year term expiring on May 10, 2018; however, if DPL has not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility shall be July 15, 2016.  At September 30, 2014, there was one letter of credit in the amount of $2.3 million outstanding, with the remaining $97.7 million available to DPL.Fees associated with this facility were not material during the three months or nine months ended September 30, 2014 or 2013.

DPL’s unsecured revolving credit agreement and unsecured term loan have two financial covenants.  The first financial covenant, a 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, an 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. 

DPL’s unsecured revolving credit agreement and unsecured term loan restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities under certain credit rating scenarios.

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 of debt 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.  In December 2013, DPL executed an open market repurchase and successfully bought back $20 million of the first tranche and $20 million of the second tranche.  DPL paid a $1.9 million and a $0.5 million premium, respectively, to repurchase these bonds. Subsequent to repurchasing these bonds DPL immediately retired them. 

On September 6, 2014, DPL announced its intent to purchase a maximum of $280.0 million of aggregate principal of the Senior Unsecured bonds maturing October 2016 through a tender offer.  On October 6, DPL partially funded the tender by closing on a new bond issuance of $200.0 million of Senior Unsecured notes maturing October 2019, which were priced at 6.75% and increased the maximum amount of the tender to $300.0 million.  The remainder of the tender was funded with cash on hand and the use of the DPL revolving line of credit.  The tender offer expired on October 20, 2014.  The net balance paid with cash or current borrowings of $100.0 million has been reclassified as current as of September 30, 2014.

In October 2014, DPLrepaid$5.0 million of the note due to Capital Trust II, which used the funds to repurchase securities in the open market at a slight premium.  Subsequent to repurchasing these securities Capital Trust II immediately retired them.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. 

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6.  Income Taxes 

The following table details the effective tax rates for the three and nine months endedSeptember 30, 2014 and 2013. 

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	2014	2013
DPL	(71.5)%	25.4%	(34.2)%	21.5%

Income tax expense for the three and nine months endedSeptember 30, 2014 and 2013 was calculated using the estimated annual effective income tax rates for 2014 and 2013 of (42.3)% and 31.0%, respectively.  For the three and nine months endedSeptember 30, 2014 and September 30, 2013, management estimated 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 September 30, 2014, DPL’s current period effective rate is less than the estimated annual effective rate due to a 2014 adjustment to the tax reserves due to uncertain tax positionsrelated to the expiration of the statute of limitations on the 2010 tax year.

For the nine months ended September 30, 2014, the decrease in DPL’s effective rate compared to the same period in 2013 primarily reflects decreased pre-tax earnings related to the non-deductible goodwill impairment during the first quarter of 2014, which is treated as a permanent item in the annual effective income tax rate, and a 2014 adjustment to the tax reserves due to uncertain tax positionsrelated to the expiration of the statute of limitations on the 2010 tax year. 

For the nine months endedSeptember 30, 2013,  DPL’s current period effective rate was less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 IRS examination in the first quarter of 2013 and a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years.

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 ERISA and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three and nine months endedSeptember 30, 2014 or 2013, respectively. 

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 and nine months ended September 30, 2014 and 2013 was: 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended				Three months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	1.5	$	1.8	$	-	$	-
Interest cost		4.3		3.8		0.2		0.2
Expected return on plan assets (a)		(5.8)		(5.8)		-		-
Amortization of unrecognized:
Prior service cost		0.4		0.3		-		-
Actuarial loss / (gain)		0.9		1.3		(0.1)		(0.1)

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Net periodic benefit cost $ 1.3  $ 1.4  $ 0.1  $ 0.1 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	4.5	$	5.4	$	0.1	$	0.1
Interest cost		13.1		11.6		0.6		0.6
Expected return on plan assets (a)		(17.2)		(17.6)		(0.1)		(0.2)
Amortization of unrecognized:
Prior service cost		1.1		1.1		-		-
Actuarial loss / (gain)		2.6		3.7		(0.4)		(0.3)
Net periodic benefit cost	$	4.1	$	4.2	$	0.2	$	0.2

(a) For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used.  GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2014 and 2013 net periodic benefit cost was approximately $351 million and $346 million, respectively. 

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions	Pension		Postretirement
2014	$	6.3	$	0.5
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

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 September 30, 2014 and December 31, 2013.  Further information about the fair value of our derivative instruments can be found in Note 9.

	September 30, 2014				December 31, 2013
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.6		3.3		4.4
Debt securities		5.0		5.0		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total Assets	$	9.0	$	10.0	$	10.3	$	11.5
Liabilities

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Debt $ 2,264.4  $ 2,345.9  $ 2,294.4  $ 2,334.6 

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 carrying value.

Debt 

The carrying value of DPL’s debt in place at the Merger was adjusted to fair value at the Merger date.  The carrying value of this debt is net of subsequent amortization of any premiums or discounts recognized at the merger date.  Debt issued subsequent to the Merger is carried at issue cost, net of unamortized premium or discount.  Unrealized gains or losses are not recognized in the financial statements because debt is presented at cost or 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 2016 to 2061. 

Master Trust Assets 

DP&L established Master Trusts 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 deferred assets on the balance sheets and classified as available for sale.  Any unrealized gains or losses are recorded in AOCI until the securities are sold. 

DPL had  $0.6 million($0.4million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2014 and $0.9 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses in AOCI at December 31, 2013. 

During the nine months ended September 30, 2014,  $0.6 million ($0.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  An immaterial amount of unrealized gains are expected to be reversed to earnings over the next twelve months to facilitate the distribution of benefits.

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 September 30, 2014 and December 31, 2013 and the respective category within the fair value hierarchy for DPL was determined as follows: 

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.1	$	0.1	$	-	$	-
Equity securities		3.6		3.6		-		-
Debt securities		5.0		5.0		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		10.0		9.1		0.9		-
Derivative Assets
Forward power contracts		11.2		-		11.2		-
Total Derivative assets		11.2		-		11.2		-
Total Assets	$	21.2	$	9.1	$	12.1	$	-
Liabilities
Derivative Liabilities
FTRs	$	1.0	$	-	$	-	$	1.0
Heating oil		0.1		0.1		-		-
Forward power contracts		26.9		-		26.9		-
Total Derivative liabilities		28.0		0.1		26.9		1.0
Long-term debt		2,345.9		-		2,327.6		18.3
Total Liabilities	$	2,373.9	$	0.1	$	2,354.5	$	19.3

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		11.5		10.6		0.9		-
Derivative assets
FTRs		0.2		-		-		0.2
Heating oil futures		0.2		0.2		-		-
Forward power contracts		13.4		-		13.4		-
Total Derivative assets		13.8		0.2		13.4		0.2
Total Assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Derivative liabilities
Forward power contracts	$	10.6	$	-		10.6	$	-
Total Derivative liabilities		10.6		-		10.6		-
Long-term debt		2,334.6		-		2,316.1		18.5
Total Liabilities	$	2,345.2	$	-	$	2,326.7	$	18.5

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).  FTRs 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. 

Approximately 98%  of the inputs to the fair value of our derivative instruments are from quoted market prices. 

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. 

Non-recurring Fair Value Measurements 

We use the cost approach to determine the fair value of our AROs, which is 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.  There was not a material change in our AROs in thethree months ended September 30, 2014.  AROs increased $1.6 million during the nine months ended September 30, 2014,primarily due to a new study of the asbestos and underground storage tank AROs at Hutchings in the first quarter of 2014.  Additions to AROs were not material during the three and nine months ended September 30, 2013.

When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance.  Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes Goodwill and Long-lived assets measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:

$ in millions	Nine months ended September 30, 2014
		Carrying	Fair Value							Gross
		Amount (c)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (East Bend)	$	14.2	$	-	$	-	$	2.7	$	11.5
Goodwill (b)
DPLER Reporting unit	$	135.8	$	-	$	-	$	-	$	135.8

(a)See Note 13 for further information

(b)See Note 12 for further information

(c)Carrying amount at date of valuation

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 normal purchase/normal sale, cash flow hedges or marked to market each reporting period. 

At September 30, 2014,  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		17.4		-		17.4
Heating oil futures		Mark to Market	Gallons		672.0		-		672.0
Forward power contracts		Cash Flow Hedge	MWh		40.7		(3,543.0)		(3,502.3)
Forward power contracts		Mark to Market	MWh		2,320.0		(3,357.9)		(1,037.9)

At December 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		7.1		-		7.1
Heating oil futures		Mark to Market	Gallons		1,428.0		-		1,428.0
Forward power contracts		Cash Flow Hedge	MWh		140.4		(4,705.7)		(4,565.3)
Forward power contracts		Mark to Market	MWh		3,177.8		(2,883.1)		294.7

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Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge  transactions.  The fair value of cash flow hedges 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 entered into interest rate derivative contracts to manage interest rate exposure related to borrowings of fixed-rate debt.  These interest rate derivative contracts were settled in the third quarter of 2013.  We do not hedge all interest rate exposure.  We reclassify gains and losses on interest rate derivative hedges out of AOCI and into earnings in those periods in which hedged interest payments occur.

The following tables provide information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months ended September 30, 2014 and 2013:

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(12.4)	$	18.8	$	(1.1)	$	12.8
Net gains / (losses) associated with current period hedging transactions		1.2		-		(0.2)		6.4
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.2)		-		-
Revenues		3.4		-		0.3		-
Purchased power		0.2		-		1.0		-
Ending accumulated derivative gain / (loss) in AOCI	$	(7.6)	$	18.6	$	-	$	19.2

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	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	1.4	$	19.2	$	(3.0)	$	0.5
Net gains / (losses) associated with current period hedging transactions		(23.8)		-		-		18.7
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.6)		-		-
Revenues		15.4		-		1.3		-
Purchased power		(0.6)		-		1.7		-
Ending accumulated derivative gain / (loss) in AOCI	$	(7.6)	$	18.6	$	-	$	19.2
Portion expected to be reclassified to earnings in the next twelve months (a)	$	(7.3)	$	(0.6)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		27		0

(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 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, 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 or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or 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 is 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. 

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The following tables present the amount and classification within the Condensed Consolidated Statements of Results of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2014 and 2013. 

For the three months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.3	$	(2.3)	$	(2.2)
Realized gain / (loss)		-		0.1		(2.1)		(2.0)
Total	$	(0.2)	$	0.4	$	(4.4)	$	(4.2)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Purchased power		-		0.4		(4.4)		(4.0)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	0.4	$	(4.4)	$	(4.2)

For the three months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain	$	0.1	$	1.3	$	0.1	$	1.5
Realized gain / (loss)		0.1		-		(0.8)		(0.7)
Total	$	0.2	$	1.3	$	(0.7)	$	0.8
Recorded in Income Statement: gain / (loss)
Purchased power	$	-	$	1.3	$	(0.7)	$	0.6
Fuel		0.1		-		-		0.1
O&M		0.1		-		-		0.1
Total	$	0.2	$	1.3	$	(0.7)	$	0.8

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For the nine months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized loss	$	(0.3)	$	(1.2)	$	(6.0)	$	(7.5)
Realized gain / (loss)		0.1		0.7		(3.6)		(2.8)
Total	$	(0.2)	$	(0.5)	$	(9.6)	$	(10.3)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: loss
Purchased power		-		(0.5)		(9.6)		(10.1)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	(0.5)	$	(9.6)	$	(10.3)

For the nine months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.4	$	10.5	$	10.7
Realized gain		-		1.2		0.5		1.7
Total	$	(0.2)	$	1.6	$	11.0	$	12.4
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Purchased power		-		1.6		11.0		12.6
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	1.6	$	11.0	$	12.4

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.

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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. 

Fair Values of Derivative Instruments
at September 30, 2014
				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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.9	$	(0.9)	$	-	$	-
Forward power contracts	MTM		6.3		(5.4)		-		0.9
Heating oil	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.7		(0.6)		(0.1)		-
Forward power contracts	MTM		3.3		(2.5)		-		0.8
Total assets		$	11.2	$	(9.4)	$	(0.1)	$	1.7
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	12.0	$	(0.9)	$	(9.8)	$	1.3
Forward power contracts	MTM		10.2		(5.4)		(2.8)		2.0
Heating oil	MTM		0.1		-		(0.1)		-
FTRs	MTM		1.0		-		-		1.0
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.3		(0.6)		(0.7)		-
Forward power contracts	MTM		3.4		(2.6)		(0.7)		0.1
Total liabilities		$	28.0	$	(9.5)	$	(14.1)	$	4.4

Forward power contracts with a value of $0.1 million have been omitted from the above table as they had been, but no longer need to be, accounted for as derivatives at fair value.  These derivatives are being amortized to earnings over the remaining term of the associated forward contracts. 

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Fair Values of Derivative Instruments
at December 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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2		-		-		0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

Forward power contracts with a short-term asset position of $0.9million and a long-term asset position of $0.1 million have been omitted from the above table as they had been, but no longer need to be, accounted for as derivatives at fair value.  These derivatives are being amortized to earnings over the remaining term of the associated forward contracts.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at September 30, 2014was $28.0million.  Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  If our debt does not maintain an investment grade credit rating, our counterparties to the derivative instruments could request immediate payment or immediate and full overnight collateralization of the MTM loss.  The MTM loss positions at September 30, 2014 were offset by $14.1 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 $9.5 million.  If our counterparties were to call for collateral, we could have to post collateral for the remaining $4.4 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, 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 September 30, 2014,  DPL  had $19.0 million of guarantees to third parties for future financial or performance assurance under such agreements:  $2.0 million of guarantees on behalf of DPLER, $16.8 million of guarantees on behalf of DPLE and $0.2 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 to the beneficiaries within a certain time. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.4 million at September 30, 2014. 

To date, DPL has not incurred any losses related to the guarantees of DPLER’s, DPLE’s or 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. 

DP&L – Equity Ownership Interest

DP&L owns a 4.9%  equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP.  As of September 30, 2014,  DP&L could be responsible for the repayment of 4.9%, or $76.0 million, of a $1,550.1 million debt obligation that has maturities from 2018 to 2040.  This would only happen if OVEC defaulted on its debt payments.  As of September 30, 2014, 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, 2013.

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 September 30, 2014, cannot be reasonably determined. 

Environmental Matters

DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws.  The environmental issues that may affect us include:

· The federal CAA and state laws and regulations (including the Ohio SIP) which require compliance, obtaining permits and reporting as to air emissions,

· Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,

· Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO₂, particulates, mercury, acid gases, NO_x, and other air emissions.  DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,

· Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and may require reductions of GHGs,

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· Rules and future rules issued by the USEPA associated with the federal CWA, which prohibit the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

· Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.  The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the USEPA is reconsidering that determination and planning to finalize a new rule regulating coal combustion by-products.  A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such by-products.

In addition to 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 in an effort 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 September 30, 2014, and December 31, 2013, we had accruals of approximately $0.9 million and $1.1 million, respectively, for environmental matters and other claims.  We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated, which are disclosed in the paragraphs below.  We evaluate the potential liability related to environmental matters quarterly and may revise our accruals.  Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our EGUs and stations.  Some of these matters could have material adverse effects on the operation of the power stations.

Cross-State Air Pollution Rule

On April 29, 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) that had vacated CSAPR and remanded the case back to the D.C. Circuit Court.  On June 26, 2014, the U.S. Department of Justice, on behalf of the USEPA, filed a motion with the D.C. Circuit Court to lift the current stay on CSAPR which was granted on October 23, 2014.  The USEPA is expected to establish new effective dates for compliance with the reduced emissions levels, the first of which could take effect as early as January 2015.  Certain challenges to CSAPR by industry groups and states (including Ohio) remain pending and oral arguments have been scheduled for March 2015.  It is not possible to predict what impacts CSAPR and the pending litigation may have on our consolidated financial condition, results of operations or cash flows, but it is not expected to be material.

National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO₂ replacing the previous 24-hour standard and annual standard with a one-hour standard.  Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations recommended as non-attainment.  Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014, the USEPA proposed a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO₂ emissions.  The rule, if finalized, could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations.  DP&L is unable to determine the effect of the proposed rule on its operations.

Carbon Dioxide and Other Greenhouse Gas Emissions

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 set forth criteria for determining which facilities were required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  The U.S Supreme Court reviewed several cases addressing the USEPA’s authority to issue GHG PSD permits under Section 165 of the CAA, and on June 23, 2014 ruled that the USEPA had exceeded its statutory authority in issuing the Tailoring Rule.  However, the Supreme Court upheld the USEPA’s ability to include Best Available Control Technology (BACT) requirements for GHGs emitted by sources that are already subject to the PSD requirements for other pollutants.  Therefore, if future modifications to DP&L’s sources require PSD review for other pollutants, it may

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also trigger GHG BACT requirements.  The USEPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. 

The USEPA issued proposed GHG emissions rules for existing, modified and reconstructed generating units on June 2, 2014.  Under the proposed rules, called the Clean Power Plan, states would be judged against state-specific CO₂ emissions targets beginning in 2020, with an expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030.  For Ohio specifically, the Clean Power Plan proposes an interim goal for 2020-2029 and a proposed 2030 final goal of 1,452 pounds of CO₂ per megawatt hour and 1,338 pounds of CO₂ per megawatt hour, respectively, a reduction of approximately 28% from 2012 levels.  The proposed rule requires states to submit implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances.  The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures.  We could be required, among other things, to make efficiency improvements at our facilities.  USEPA expects to finalize this rule by June 1, 2015.  We cannot predict the effect of these proposed rules on DP&L’s operations. 

Approximately 99% of the energy we produce is generated by coal.  DP&L’s share of CO₂ emissions at generating stations we own and co-own is approximately 14 million tons annually.  Further GHG legislation or regulation implemented at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L. 

Clean Water Act – Regulation of Water Intake

On May 19, 2014, the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures.  The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  Although we do not yet know the full impact the final rules will have on our operations, the final rule may require material changes to the intake structure at Stuart Station to reduce impingement with the possibility of additional site specific requirements for reducing entrainment.  We do not believe the final rule will have a material impact on operations at any of the other DP&L facilities.

A final NPDES permit for Killen Station was issued on September 4, 2014.  We do not expect the new permit to have a material impact on Killen’s operations.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (“ASAOC”) was executed and became effective among a group of PRPs, not including DP&L, and the USEPA. 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 the PRP group in performing an RI/FS under the August 15, 2006 ASAOC. That summary

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judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th Circuit affirmed the lower court’s ruling and subsequently denied a request by the plaintiffs for rehearing.DP&L cannot predict whether the plaintiffs will appeal to the U.S. Supreme Court.DP&L is unable to predict the outcome of any such action by the plaintiffs. Additionally, the Court’s ruling and the Appeal Court affirmance of that 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.

11.  Business Segments 

DPL operates through two segments; Utility and Competitive Retail.  The Utility segment consists of the operations of DPL’s subsidiary, DP&L.  The Competitive Retail segment consists of DPL’s wholly owned subsidiaryDPLER, including DPLER’s wholly owned subsidiary, MC Squared.  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 sold to DP&L’s standard service offer customers is primarily generated at seven coal-fired power plants and DP&L distributes power to more than 515,000 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 PJM 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 274,000 customers located throughout Ohio and in Illinois.  This number includes 117,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.  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 in the “Other” column in the following tables are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs including interest expense on DPL’s debt. 

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

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The following 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 September 30, 2014
Revenues from external customers	$	329.3	$	141.3	$	8.6	$	-	$	479.2
Intersegment revenues		125.6		-		3.0		(128.6)		-
Total revenues		454.9		141.3		11.6		(128.6)		479.2
Fuel		84.5		-		0.6		-		85.1
Purchased power		152.4		128.7		0.4		(127.8)		153.7
Amortization of intangibles		-		-		0.3		-		0.3
Gross margin	$	218.0	$	12.6	$	10.3	$	(0.8)	$	240.1
Depreciation and amortization	$	36.4	$	0.3	$	(2.2)	$	-	$	34.5
Interest expense		9.4		0.1		23.8		(0.2)		33.1
Income tax expense (benefit)		13.1		1.5		(55.6)		-		(41.0)
Net income / (loss)		53.2		3.0		42.2		-		98.4
Cash capital expenditures	$	25.6	$	0.5	$	0.3	$	-	$	26.4

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended September 30, 2013
Revenues from external customers	$	289.3	$	139.7	$	12.2	$	-	$	441.2
Intersegment revenues		123.8		-		1.0		(124.8)		-
Total revenues		413.1		139.7		13.2		(124.8)		441.2
Fuel		96.7		-		2.9		0.1		99.7
Purchased power		110.4		125.6		0.9		(123.8)		113.1
Amortization of intangibles		-		-		1.8		-		1.8
Gross margin	$	206.0	$	14.1	$	7.6	$	(1.1)	$	226.6
Depreciation and amortization	$	35.8	$	0.1	$	(2.0)	$	-	$	33.9
Interest expense		10.4		0.1		20.6		(0.1)		31.0
Income tax expense (benefit)		13.2		1.4		(3.3)		-		11.3
Net income / (loss)		40.9		2.5		(10.2)		-		33.2
Cash capital expenditures	$	28.3	$	-	$	1.0	$	-	$	29.3

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$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the nine months ended September 30, 2014
Revenues from external customers	$	875.9	$	414.9	$	38.8	$	-	$	1,329.6
Intersegment revenues		376.6		-		4.1		(380.7)		-
Total revenues		1,252.5		414.9		42.9		(380.7)		1,329.6
Fuel		227.4		-		8.5		-		235.9
Purchased power		457.3		380.0		7.1		(378.2)		466.2
Amortization of intangibles		-		-		0.9		-		0.9
Gross margin	$	567.8	$	34.9	$	26.4	$	(2.5)	$	626.6
Depreciation and amortization	$	108.2	$	0.6	$	(5.1)	$	-	$	103.7
Goodwill impairment		-		-		135.8		-		135.8
Fixed-asset impairment		-		-		11.5		-		11.5
Interest expense		25.5		0.3		70.5		(0.5)		95.8
Income tax expense (benefit)		23.1		2.1		4.5		-		29.7
Net income / (loss)		76.5		4.2		(197.5)		-		(116.8)
Cash capital expenditures	$	78.6	$	0.5	$	2.5	$	-	$	81.6
At September 30, 2014
Total assets	$	3,245.3	$	100.3	$	1,536.9	$	(1,339.9)	$	3,542.6

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the nine months ended September 30, 2013
Revenues from external customers	$	805.5	$	381.9	$	23.3	$	-	$	1,210.7
Intersegment revenues		336.0		-		3.0		(339.0)		-
Total revenues		1,141.5		381.9		26.3		(339.0)		1,210.7
Fuel		269.6		-		4.2		0.2		274.0
Purchased power		276.7		340.8		1.5		(336.4)		282.6
Amortization of intangibles		-		-		5.3		-		5.3
Gross margin	$	595.2	$	41.1	$	15.3	$	(2.8)	$	648.8
Depreciation and amortization	$	104.5	$	0.4	$	(5.9)	$	-	$	99.0
Interest expense		29.7		0.4		61.5		(0.5)		91.1
Income tax expense (benefit)		29.2		4.3		(12.7)		-		20.8
Net income / (loss)		101.4		7.7		(33.1)		-		76.0
Cash capital expenditures	$	95.1	$	-	$	1.4	$	-	$	96.5
At December 31, 2013
Total assets	$	3,313.1	$	105.0	$	1,675.8	$	(1,372.4)	$	3,721.5

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12. Goodwill Impairment

During the first quarter of 2014, we performed an interim impairment test on the$135.8 million in goodwill at our DPLER reporting unit.  The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.

In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business.

During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit.  There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter. 

13. Fixed-asset Impairment

During the first quarter of 2014, DP&L tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L.  Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013.  DP&L performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach.  As a result, we recognized an asset impairment expense of $11.5 million.  In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend.  The sale price approximates the carrying value.  This transaction is expected to close by the end of 2014.

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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 September 30,				Nine months ended September 30,
$ in millions	2014		2013		2014		2013
Revenues	$	454.9	$	413.1	$	1,252.5	$	1,141.5
Cost of revenues:
Fuel		84.5		96.7		227.4		269.6
Purchased power		152.4		110.4		457.3		276.7
Total cost of revenues		236.9		207.1		684.7		546.3
Gross margin		218.0		206.0		567.8		595.2
Operating expenses:
Operation and maintenance		85.9		87.6		265.9		270.4
Depreciation and amortization		36.4		35.8		108.2		104.5
General taxes		20.2		18.2		67.1		57.4
Total operating expenses		142.5		141.6		441.2		432.3
Operating income		75.5		64.4		126.6		162.9
Other income / (expense), net:
Investment income		0.2		0.1		0.6		1.7
Interest expense		(9.4)		(10.4)		(25.5)		(29.7)
Other income / (expense)		-		-		(2.1)		(4.3)
Total other expense		(9.2)		(10.3)		(27.0)		(32.3)
Earnings before income taxes		66.3		54.1		99.6		130.6
Income tax expense		13.1		13.2		23.1		29.2
Net income		53.2		40.9		76.5		101.4
Dividends on preferred stock		0.3		0.2		0.7		0.6
Income attributable to common stock	$	52.9	$	40.7	$	75.8	$	100.8
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
	Three months ended September 30,				Nine months ended September 30,
$ in millions	2014		2013		2014		2013
Net income	$	53.2	$	40.9	$	76.5	$	101.4
Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax benefit of $0.2, $0.1, $0.2 and $0.9 for each respective period		(0.4)		(0.2)		(0.6)		(1.8)
Reclassification to earnings, net of income tax expense of $(0.1), $(0.2), $(0.2) and $(0.7) for each respective period		0.2		0.4		0.4		1.4
Total change in fair value of available-for-sale securities		(0.2)		0.2		(0.2)		(0.4)
Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(0.7), $0.1, $9.9 and $0.0 for each respective period		1.4		(0.3)		(26.3)		-
Reclassification to earnings, net of income tax expense of $(1.9), $(0.9), $(6.7) and $(2.2) for each respective period		3.2		1.0		15.3		2.3
Total change in fair value of derivatives		4.6		0.7		(11.0)		2.3
Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $(0.3), $(0.5), $(1.0) and $(1.5) for each respective period		0.7		0.9		2.1		2.7
Total change in unfunded pension obligation		0.7		0.9		2.1		2.7
Other comprehensive income / (loss)		5.1		1.8		(9.1)		4.6
Net comprehensive income	$	58.3	$	42.7	$	67.4	$	106.0
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
	Nine months ended September 30,
$ in millions	2014		2013
Cash flows from operating activities:
Net income	$	76.5	$	101.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		108.2		104.5
Deferred income taxes		2.9		27.1
Changes in certain assets and liabilities:
Accounts receivable		4.8		30.7
Inventories		(3.5)		18.5
Prepaid taxes		0.2		0.8
Taxes applicable to subsequent years		50.5		50.0
Deferred regulatory costs, net		4.8		12.4
Accounts payable		7.9		(7.3)
Accrued taxes payable		(40.8)		(48.2)
Accrued interest payable		(5.7)		2.7
Pension, retiree and other benefits		(5.2)		7.1
Unamortized investment tax credit		(1.9)		(1.9)
Other		(9.5)		(13.9)
Net cash from operating activities		189.2		283.9
Cash flows from investing activities:
Capital expenditures		(78.6)		(95.1)
Purchase of emission allowances		(0.2)		-
Purchase of renewable energy credits		(3.4)		(3.3)
Decrease / (increase) in restricted cash		(9.4)		3.4
Insurance proceeds		0.4		12.1
Proceeds from sale of property		-		0.8
Other investing activities, net		1.1		(1.7)
Net cash from investing activities		(90.1)		(83.8)

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (cont.)
	Nine months ended September 30,
$ in millions	2014		2013
Net cash from financing activities:
Dividends paid on common stock to parent		(90.0)		(155.0)
Dividends paid on preferred stock		(0.7)		(0.6)
Issuance of notes payable - related party		15.0		-
Repayment of notes payable - related party		(15.0)		-
Issuance of long-term debt		-		444.2
Deferred finance costs		(0.2)		(6.7)
Retirement of long-term debt		(0.1)		(0.1)
Net cash from financing activities		(91.0)		281.8
Cash and cash equivalents:
Net change		8.1		481.9
Balance at beginning of period		22.9		28.5
Cash and cash equivalents at end of period	$	31.0	$	510.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	26.1	$	28.7
Income taxes paid / (refunded), net	$	0.2	$	(20.3)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	6.7	$	5.4
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
	September 30,		December 31,
$ in millions	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	31.0	$	22.9
Restricted cash		22.5		13.0
Accounts receivable, net (Note 2)		142.8		147.5
Inventories (Note 2)		85.2		81.7
Taxes applicable to subsequent years		18.0		68.5
Regulatory assets, current (Note 3)		30.0		20.8
Other prepayments and current assets		43.1		32.5
Total current assets		372.6		386.9
Property, plant & equipment:
Property, plant & equipment		5,161.2		5,105.3
Less: Accumulated depreciation and amortization		(2,539.6)		(2,448.1)
		2,621.6		2,657.2
Construction work in process		65.1		60.9
Total net property, plant & equipment		2,686.7		2,718.1
Other non-current assets:
Regulatory assets, non-current (Note 3)		147.8		159.7
Intangible assets, net of amortization		7.7		8.3
Other deferred assets		30.5		40.1
Total other non-current assets		186.0		208.1
Total assets	$	3,245.3	$	3,313.1
See Notes to Condensed Financial Statements.
These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
	September 30,		December 31,
$ in millions	2014		2013
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Current portion of long-term debt (Note 5)	$	0.1	$	0.2
Accounts payable		73.9		73.9
Accrued taxes		108.2		81.0
Accrued interest		4.1		9.6
Customer security deposits		34.5		33.1
Regulatory liabilities, current		10.0		-
Other current liabilities		62.3		59.7
Total current liabilities		293.1		257.5
Non-current liabilities:
Long-term debt (Note 5)		877.0		876.9
Deferred taxes		629.6		632.3
Taxes payable		-		76.5
Regulatory liabilities, non-current		123.7		121.1
Pension, retiree and other benefits		42.7		51.6
Unamortized investment tax credit		23.0		24.9
Other deferred credits		52.6		45.4
Total non-current liabilities		1,748.6		1,828.7
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		803.5		803.5
Accumulated other comprehensive loss		(35.8)		(26.7)
Retained earnings		412.6		426.8
Total common shareholder's equity		1,180.7		1,204.0
Total liabilities and shareholder's equity	$	3,245.3	$	3,313.1
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.  Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated.  DP&L has the exclusive right to provide such distribution and transmission services to its more than 515,000 customers located in West Central Ohio.  Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense.  DP&L's sales reflect the general economic conditions, seasonal weather patterns,retail competition in our service territoryand the market price of electricity.  DP&L sells any excess energy and capacity into the wholesale market.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.  While the OCC filed an application for rehearing on this Commission Order, it was denied by final order issued on July 23, 2014.  DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.DP&L is a subsidiary of DPL. 

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 1,142 people as of September 30, 2014.  Approximately 63% of all employees are under a collective bargaining agreement which expires on October 31, 2017.  The current collective bargaining agreement was ratified by the membership on October 30, 2014.

Financial Statement Presentation

DP&L does not have any subsidiaries.  DP&L has undivided ownership interests in seven coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of 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 Statements of Results 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, 2013. 

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 September 30, 2014; our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013.  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 EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014. 

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

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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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; intangibles and assets and liabilities related to employee benefits.

Regulatory Accounting

As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations,”which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory assets can also represent performance incentives permitted by the regulator, such as with our CCEM energy efficiency program.  Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices.  Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable.  In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment.  To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.  Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs.  It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval.  Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.  See Note 3 for more information about Regulatory Assets.

Property, Plant & 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 except for the impact of asset impairments recorded for certain generating plants.  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. 

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 and nine months ended September 30, 2014 and 2013, gains from the sale of emission allowances were immaterial.

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 not included in revenue.  The amounts of such taxes collected for the three months ended September 30, 2014 and 2013 were $12.5 million and $13.0 million, respectively.  The amounts of such taxes collected for the nine months ended September 30, 2014 and 2013 were $38.5 million and $38.0 million, respectively.

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Related Party Transactions 

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DP&L.  The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations.  This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
DP&L Revenues:
Sales to DPLER (including MC Squared) (a)	$	125.6	$	123.8	$	376.6	$	336.0
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.7)	$	(2.1)	$	(2.2)
Expense recoveries for services provided to DPLER (c)	$	0.5	$	1.3	$	1.6	$	3.8
Transactions with the Service Company
Charges for services provided	$	9.0	$	-	$	28.1	$	-

DP&L Customer security deposits:	At September 30, 2014		At December 31, 2013
Deposits received from DPLER (d)	$	20.1	$	19.2
Balances with the Service Company
Net prepaid / (payable) to the Service Company	$	9.4	$	-

(a)DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers.  The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase inDP&L’s sales to DPLER during the nine months endedSeptember 30, 2014, compared to the nine months endedSeptember 30, 2013, is primarily due to an increase in customers.

(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

Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016.  ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.  There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the

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entity’s ability to continue as a going concern.  This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application.  The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns.  Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.  We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” effective for annual and interim periods beginning after December 15, 2014.  ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results.  In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes.  For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes.  Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact on our overall results of operations, financial position or cash flows.

2.  Supplemental Financial Information 

Accounts receivable and Inventories are as follows at September 30, 2014 and December 31, 2013:

	September 30,		December 31,
$ in millions	2014		2013
Accounts receivable, net:
Unbilled revenue	$	36.0	$	47.2
Customer receivables		70.3		58.2
Amounts due from partners in jointly owned plants		10.4		15.8
Other		27.0		27.2
Provision for uncollectible accounts		(0.9)		(0.9)
Total accounts receivable, net	$	142.8	$	147.5
Inventories, at average cost:
Fuel and limestone	$	48.5	$	42.9
Plant materials and supplies		35.0		37.0
Other		1.7		1.8
Total inventories, at average cost	$	85.2	$	81.7

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Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months endedSeptember 30, 2014 and 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended				Nine months ended
		September 30,				September 30,
$ in millions		2014		2013		2014		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income	$	0.3	$	0.6	$	0.6	$	2.1
	Tax expense		(0.1)		(0.2)		(0.2)		(0.7)
	Net of income taxes		0.2		0.4		0.4		1.4
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.2)		(0.6)		(0.8)		(1.8)
	Revenue		4.9		0.4		23.4		2.1
	Purchased power		0.4		2.0		(0.6)		4.2
	Total before income taxes		5.1		1.8		22.0		4.5
	Tax expense		(1.9)		(0.8)		(6.7)		(2.2)
	Net of income taxes		3.2		1.0		15.3		2.3
Amortization of defined benefit pension items (Note 7):
	Reclassification to Other income / (deductions)		1.0		1.4		3.1		4.2
	Tax benefit		(0.3)		(0.5)		(1.0)		(1.5)
	Net of income taxes		0.7		0.9		2.1		2.7
Total reclassifications for the period, net of income taxes		$	4.1	$	2.3	$	17.8	$	6.4

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2014 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, 2014	$	0.8	$	6.2	$	(33.7)	$	(26.7)
Other comprehensive loss before reclassifications		(0.6)		(26.3)		-		(26.9)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.4		15.3		2.1		17.8
Net current period other comprehensive loss		(0.2)		(11.0)		2.1		(9.1)
Balance September 30, 2014	$	0.6	$	(4.8)	$	(31.6)	$	(35.8)

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3.  Regulatory Assets 

DP&L’s regulatory asset for deferred storm costs represents costs incurred to repair the damage caused to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. Such costs are included in Regulatory Assets, non-current on the accompanying Condensed Balance Sheets and were $22.3 million and $25.6 million as of March 31, 2014 and December 31, 2013, respectively. DP&L filed an application with the PUCO in 2012 to recover these costs.  The main issue in the case was the level of storm costs that should be recoverable. On April 14, 2014, DP&L reached an agreement in principle with the PUCO Staff whereby DP&L would recover storm costs of $22.3 million from all customers on a non-bypassable basis.  As a result of these developments, we reduced the regulatory asset balance to $22.3 million as our best estimate of the amount that is probable of recovery.  In accordance with FASC 980 “Regulated Operations”, the reduction was recognized as a current period expense, which is included in Operation and maintenanceand the corresponding adjustment to carrying costs which is included in interest expense on the accompanying Condensed Statements of Results of Operations.  A stipulation was finalized and filed at the PUCO and a hearing took place the first week of June 2014.  A decision is expected before the end of the year.

In August 2014, the PUCO issued an order in a case relating to review of DP&L’s fuel cost recovery mechanism for the calendar year 2012. The order included the disallowance of an immaterial amount of fuel costs. The impact of the order issued was a reversal in the third quarter of a previously established$2.6 million reserve.

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities, various peaking facilitiesand 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 September 30, 2014,  DP&L had $19.0 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 & 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 at September 30, 2014, is as follows: 

	DP&L Share			DP&L Carrying value
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	$	74	$	-	No
Conesville Unit 4	16.5	129		22		3		-	Yes
East Bend Station	31.0	186		2		1		-	Yes
Killen Station	67.0	402		624		311		2	Yes
Miami Fort Units 7 and 8	36.0	368		361		159		1	Yes
Stuart Station	35.0	808		751		319		12	Yes
Zimmer Station	28.1	365		1,100		670		4	Yes
Transmission (at varying percentages)		n/a		98		62		-
Total		2,465	$	3,034	$	1,599	$	19

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Beckjord Unit 6, in which DP&L has a 50% ownership interest, is currently inoperable, and there are no plans to return it to service.  This unit was retired effective October 1, 2014.

In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend.  This transaction is expected to close by the end of 2014.

5.  Debt Obligations 

Long-term debt

	September 30,		December 31,
$ in millions	2014		2013
First mortgage bonds due in September 2016 - 1.875%		445.0		445.0
Pollution control series due in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series due in January 2034 - 4.8%		179.1		179.1
Pollution control series due in September 2036 - 4.8%		100.0		100.0
Pollution control series due in November 2040 - rates from: 0.04% - 0.15% and 0.05% - 0.24% (a)		100.0		100.0
U.S. Government note due in February 2061 - 4.2%		18.1		18.2
Unamortized debt discount		(0.5)		(0.7)
Total non-current portion of long-term debt	$	877.0	$	876.9

Current portion of long-term debt

	September 30,		December 31,
$ in millions	2014		2013
U.S. Government note due in February 2061 - 4.2%		0.1	$	0.1
Capital lease obligations		-		0.1
Total current portion of long-term debt	$	0.1	$	0.2

(a) Range of interest rates for the nine months ended September 30, 2014 and the twelve months ended December 31, 2013, respectively. 

At September 30, 2014, maturities of long-term debt are as follows:

Due within the twelve months ending September 30,
$ in millions
2015	$	0.1
2016		445.1
2017		0.1
2018		0.1
2019		0.1
Thereafter		432.1
		877.6
Unamortized discounts		(0.5)
Total long-term debt	$	877.1

On May 10, 2013, DP&L closed a  $300.0 million unsecured revolving credit agreement with a syndicated bank group. This $300.0 million facility has a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provides DP&Lthe ability to increase the size of the facility by an additional $100.0 million.  At September 30, 2014, there were two letters of credit in the amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L.  Fees associated with this revolving credit facility were not material during the three and nine months endedSeptember 30, 2014 or 2013.

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DP&L’s unsecured revolving credit agreements and DP&L’s standby letter of credit have two financial covenants, the first measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter.  The second financial covenant compares EBITDA to Interest Expense.  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.

On March 31, 2014, DP&L borrowed $15.0 million from DPL at an interest rate of LIBOR plus 2.0%.  This note was due on or before April 30, 2014 and was repaid on April 30, 2014.

Substantially all property, plant & equipment of DP&Lis subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. 

6.  Income Taxes 

The following table details the effective tax rates for the three and nine months endedSeptember 30, 2014 and 2013. 

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	2014	2013
DP&L	19.8%	24.4%	23.2%	22.5%

Income tax expense for the three and nine months endedSeptember 30, 2014 and 2013 was calculated using the estimated annual effective income tax rates for 2014 and 2013 of 30.5% and 29.5%, respectively.  For the three and nine months endedSeptember 30,2014 and 2013 management estimated 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 and nine months ended September 30, 2014, DP&L’s current period effective rate is less than the estimated annual effective rate due to a 2014 adjustment to the tax reserves due to uncertain tax positionsrelated to the expiration of the statute of limitations on the 2010 tax year.

For the nine months endedSeptember 30, 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 Internal Revenue Service examination in the first quarter of 2013 and the adjustment to the tax reserves due to uncertain tax positionsrelated to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years.

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 ERISA and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three and nine months endedSeptember 30, 2014 or 2013, respectively.

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 and nine months endedSeptember 30, 2014 and 2013 was:

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended				Three months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	1.5	$	1.8	$	-	$	-
Interest cost		4.3		3.8		0.2		0.2
Expected return on plan assets (a)		(5.7)		(5.8)		(0.1)		(0.1)
Amortization of unrecognized:
Prior service cost		0.7		0.7		0.1		0.1
Actuarial loss / (gain)		1.6		2.3		(0.2)		(0.2)
Net periodic benefit cost	$	2.4	$	2.8	$	-	$	-

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	4.4	$	5.4	$	0.1	$	0.1
Interest cost		13.0		11.6		0.6		0.6
Expected return on plan assets (a)		(17.0)		(17.6)		(0.2)		(0.2)
Amortization of unrecognized:
Prior service cost		2.1		2.1		0.1		0.1
Actuarial loss / (gain)		4.8		6.9		(0.5)		(0.5)
Net periodic benefit cost	$	7.3	$	8.4	$	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 2014 and 2013 net periodic benefit cost was approximately $351 million and $346 million, respectively. 

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions	Pension		Postretirement
2014	$	6.3	$	0.5
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

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. 

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The following table presents the fair value and cost of our non-derivative instruments at September 30, 2014 and December 31, 2013.  Further information about the fair value of our derivative instruments can be found in Note 9.

	September 30, 2014				December 31, 2013
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.6		3.3		4.4
Debt securities		5.0		5.0		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total assets	$	9.0	$	10.0	$	10.3	$	11.5
Liabilities
Debt	$	877.1	$	884.7	$	877.1	$	859.6

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed 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 2016 to 2061. 

Master Trust Assets 

DP&L established Master Trusts 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 that 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. 

DP&L had $0.9 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2014 and $1.2 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2013. 

During the nine months endedSeptember 30, 2014,  $0.6 million $0.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  An immaterial amount of unrealized gains are expected to be reversed to earnings over the next twelve months to facilitate the disbursement of benefits.

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 September 30, 2014 and December 31, 2013 and the respective category within the fair value hierarchy for DP&L was determined as follows: 

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.1	$	0.1	$	-	$	-
Equity securities		3.6		3.6		-		-
Debt securities		5.0		5.0		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		10.0		9.1		0.9		-
Derivative assets
FTRs		-		-		-		-
Heating oil		-		-		-		-
Forward power contracts		11.7		-		11.7		-
Total derivative assets		11.7		-		11.7		-
Total assets	$	21.7	$	9.1	$	12.6	$	-
Liabilities
Derivative liabilities
FTRs	$	1.0	$	-	$	-	$	1.0
Heating oil		0.1		0.1		-		-
Forward power contracts		26.9		-		26.9		-
Total derivative liabilities		28.0		0.1		26.9		1.0
Long-term debt		884.7		-		866.4		18.3
Total liabilities	$	912.7	$	0.1	$	893.3	$	19.3

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Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		11.5		10.6		0.9		-
Derivative assets
Heating oil futures		0.2		0.2		-		-
FTRs		0.2		-		-		0.2
Forward power contracts		13.4		-		13.4		-
Total Derivative assets		13.8		0.2		13.4		0.2
Total assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Derivative liabilities
Forward power contracts		10.6		-		10.6		-
Total Derivative liabilities		10.6		-		10.6		-
Long-term debt		859.6		-		841.1		18.5
Total liabilities	$	870.2	$	-	$	851.7	$	18.5

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).  FTRs 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 98% 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 is estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the

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approximate future disposal cost as determined by market information, historical information or other management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  There was not a material change in our AROs in the three months ended September 30, 2014.  Additions to AROs for the three and nine months ended September 30, 2014 were $1.7 million, primarily due to a new study of the asbestos and underground storage tank AROs at Hutchings in the first quarter of 2014.  Additions to AROs were not material during the three and nine months endedSeptember 30, 2013. 

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 September 30, 2014,  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		17.4		-		17.4
Heating oil futures		Mark to Market	Gallons		672.0		-		672.0
Forward power contracts		Cash Flow Hedge	MWh		40.7		(3,543.0)		(3,502.3)
Forward power contracts		Mark to Market	MWh		2,320.0		(3,463.5)		(1,143.5)

At December 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		7.1		-		7.1
Heating oil futures		Mark to Market	Gallons		1,428.0		-		1,428.0
Forward power contracts		Cash Flow Hedge	MWh		140.4		(4,705.7)		(4,565.3)
Forward power contracts		Mark to Market	MWh		3,172.4		(2,888.5)		283.9

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 tables provide information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months endedSeptember 30, 2014 and 2013: 

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(14.0)	$	4.6	$	(1.9)	$	6.1
Net gains / (losses) associated with current period hedging transactions		1.4		-		(0.3)		-
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.2)		-		(0.6)
Revenues		3.2		-		0.3		-
Purchased power		0.2		-		1.3		-
Ending accumulated derivative gain / (loss) in AOCI	$	(9.2)	$	4.4	$	(0.6)	$	5.5

	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	1.0	$	5.2	$	(4.7)	$	7.3
Net losses associated with current period hedging transactions		(26.3)		-		-		-
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.8)		-		(1.8)
Revenues		16.6		-		1.4		-
Purchased power		(0.5)		-		2.7		-
Ending accumulated derivative gain / (loss) in AOCI	$	(9.2)	$	4.4	$	(0.6)	$	5.5
Portion expected to be reclassified to earnings in the next twelve months (a)	$	(7.2)	$	(1.1)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		27		0

(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 Condensed 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. 

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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 Statements of Results of Operations on an accrual basis. 

Regulatory Assets and Liabilities 

In accordance with regulatory accounting under GAAP, a cost or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or 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 is 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 present the amount and classification within the Condensed Statements of Results of Operations or Condensed Balance Sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2014 and 2013:  

For the three months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.3	$	(2.7)	$	(2.6)
Realized gain / (loss)		-		0.1		(2.1)		(2.0)
Total	$	(0.2)	$	0.4	$	(4.8)	$	(4.6)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		(0.3)		(0.3)
Purchased power		-		0.4		(4.5)		(4.1)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	0.4	$	(4.8)	$	(4.6)

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For the three months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	0.1	$	1.3	$	(0.1)	$	1.3
Realized gain / (loss)		0.1		-		(0.8)		(0.7)
Total	$	0.2	$	1.3	$	(0.9)	$	0.6
Recorded in Income Statement: gain / (loss)
Revenues	$	-	$	-	$	0.1	$	0.1
Purchased power		-		1.3		(1.0)		0.3
Fuel		0.1		-		-		0.1
O&M		0.1		-		-		0.1
Total	$	0.2	$	1.3	$	(0.9)	$	0.6

For the nine months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized loss	$	(0.3)	$	(1.2)	$	(5.7)	$	(7.2)
Realized gain / (loss)		0.1		0.7		(3.0)		(2.2)
Total	$	(0.2)	$	(0.5)	$	(8.7)	$	(9.4)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		1.0		1.0
Purchased power		-		(0.5)		(9.7)		(10.2)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	(0.5)	$	(8.7)	$	(9.4)

For the nine months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.4	$	8.9	$	9.1
Realized gain		-		1.2		1.1		2.3
Total	$	(0.2)	$	1.6	$	10.0	$	11.4
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		0.2		0.2
Purchased power		-		1.6		9.8		11.4
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	1.6	$	10.0	$	11.4

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. 

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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. 

Fair Values of Derivative Instruments
at September 30, 2014
				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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.9	$	(0.9)	$	-	$	-
Forward power contracts	MTM		6.5		(5.4)		-		1.1
Heating oil futures	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.7		(0.6)		(0.1)		-
Forward power contracts	MTM		3.6		(2.6)		-		1.0
Total assets		$	11.7	$	(9.5)	$	(0.1)	$	2.1
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	12.0	$	(0.9)	$	(9.8)	$	1.3
Forward power contracts	MTM		10.2		(5.4)		(2.8)		2.0
Heating oil futures	MTM		0.1		-		(0.1)		-
FTRs	MTM		1.0		-		-		1.0
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.3		(0.6)		(0.7)		-
Forward power contracts	MTM		3.4		(2.6)		(0.7)		0.1
Total liabilities		$	28.0	$	(9.5)	$	(14.1)	$	4.4

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The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2013:

Fair Values of Derivative Instruments
at December 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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2						0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, 2014 was $28.0 million.  Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  If our debt does not maintain an investment grade credit rating, our counterparties to the derivative instruments could request immediate payment or immediate and full overnight collateralization of the MTM loss.  The MTM loss positions at September 30, 2014 were offset by $14.1 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 $9.5 million.  If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $4.4 million.

10.  Shareholder’s Equity 

DP&L has 250,000,000 authorized $0.01 par value common shares, of which 41,172,173 are outstanding at September 30, 2014.  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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11.  Contractual Obligations, Commercial Commitments and Contingencies 

DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP.  As of September 30, 2014,  DP&L could be responsible for the repayment of 4.9%, or $76.0 million, of a $1,550.1 million debt obligation that has maturities from 2018 to 2040.  This would only happen if OVEC defaulted on its debt payments.  As of September 30, 2014, 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, 2013.

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 September 30, 2014, cannot be reasonably determined. 

Environmental Matters

DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws.  The environmental issues that may affect us include:

· The federal CAA and state laws and regulations (including the Ohio SIP) which require compliance, obtaining permits and reporting as to air emissions,

· Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,

· Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO₂, particulates, mercury, acid gases, NO_x, and other air emissions.  DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,

· Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and may require reductions of GHGs,

· Rules and future rules issued by the USEPA associated with the federal CWA, which prohibit the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

· Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.  The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the USEPA is reconsidering that determination and planning to propose a new rule regulating coal combustion by-products.  A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such by-products.

In addition to 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 our facilities in an effort 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 September 30, 2014, and December 31, 2013,  

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we had accruals of approximately $0.9 million and $1.1 million, respectively, for environmental matters and other claims.  We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated, which are disclosed in the paragraphs below.  We evaluate the potential liability related to 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 condition or cash flows.

We have several pending environmental matters associated with our EGUs and stations.  Some of these matters could have material adverse effects on the operation of the power stations.  

Cross-State Air Pollution Rule

On April 29, 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) that had vacated CSAPR and remanded the case back to the D.C. Circuit Court.  On June 26, 2014, the U.S. Department of Justice, on behalf of the USEPA, filed a motion with the D.C. Circuit Court to lift the current stay on CSAPR which was granted on October 23, 2014.  The USEPA is expected to establish new effective dates for compliance with the reduced emissions levels, the first of which could take effect as early as January 2015.  Certain challenges to CSAPR by industry groups and states (including Ohio) remain pending and oral arguments have been scheduled for March 2015.  It is not possible to predict what impacts CSAPR and the pending litigation may have on our consolidated financial condition, results of operations or cash flows, but it is not expected to be material.

National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO₂ replacing the previous 24-hour standard and annual standard with a one-hour standard.  Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations recommended as non-attainment.  Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014, the USEPA proposed a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO₂ emissions.  The rule, if finalized, could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations.  DP&L is unable to determine the effect of the proposed rule on its operations.

Carbon Dioxide and Other Greenhouse Gas Emissions

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 set forth criteria for determining which facilities were required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  The U.S Supreme Court reviewed several cases addressing the USEPA’s authority to issue GHG PSD permits under Section 165 of the CAA, and on June 23, 2014 ruled that the USEPA had exceeded its statutory authority in issuing the Tailoring Rule.  However, the Supreme Court upheld the USEPA’s ability to include Best Available Control Technology (BACT) requirements for GHGs emitted by sources that are already subject to the PSD requirements for other pollutants.  Therefore, if future modifications to DP&L’s sources require PSD review for other pollutants, it may also trigger GHG BACT requirements.  The USEPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis.

The USEPA issued proposed GHG emissions rules for existing, modified and reconstructed generating units on June 2, 2014.  Under the proposed rules, called the Clean Power Plan, states would be judged against state-specific CO₂ emissions targets beginning in 2020, with an expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030.  For Ohio specifically, the Clean Power Plan proposes an interim goal for 2020-2029 and a  proposed 2030 final goal of 1,452 pounds of CO₂ per megawatt hour and 1,338 pounds of CO₂ per megawatt hour, respectively, a reduction of approximately 28% from 2012 levels.  The proposed rule requires states to submit implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances.  The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures.  We could be required, among other things, to make efficiency improvements at our facilities.  USEPA expects to finalize this rule by June 1, 2015.  We cannot predict the effect of these proposed rules on DP&L’s operations.

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Approximately 99% of the energy we produce is generated by coal.  DP&L’s share of CO₂ emissions at generating stations we own and co-own is approximately 14 million tons annually.  Further GHG legislation or regulation implemented at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L. 

Clean Water Act – Regulation of Water Intake

On May 19, 2014, the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures.  The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  Although we do not yet know the full impact the final rules will have on our operations, the final rule may require material changes to the intake structure at Stuart Station to reduce impingement with the possibility of additional site specific requirements for reducing entrainment.  We do not believe the final rule will have a material impact on operations at any of the other DP&L facilities.

A final NPDES permit for Killen Station was issued on September 4, 2014.  We do not expect the new permit to have a material impact on Killen’s operations.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (“ASAOC”) was executed and became effective among a group of PRPs, not including DP&L, and the USEPA.  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 the PRP group in performing an RI/FS under the August 15, 2006 ASAOC.  That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th Circuit affirmed the lower court’s ruling and subsequently denied a request by the plaintiffs for rehearing.  DP&L cannot predict whether the plaintiffs will appeal to the U.S. Supreme Court.  DP&L is unable to predict the outcome of any such action by the plaintiffs.  Additionally, the Court’s ruling and the Appeal Court affirmance of that 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.

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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, 2013 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 sold to DP&L's SSO customers is primarily generated at seven coal-fired power plants. During 2014, DP&L is required to source 10% of the generation for its standard service offer customers through a competitive bidprocess, 60% in 2015 and 100% in 2016.  By PUCO order DP&L is required to divest its generation assets by January 1, 2017.  DP&L distributes electricity to more than 515,000 retail customers in its 24 county service area.  Principal industries located within DP&L’s service area include food processing, paper, plastic manufacturing and defense. 

DP&L's retail generation sales reflect the general economic conditions, seasonal weather patterns of the area as well as retail market conditions.  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.  DPLER has approximately 274,000 customers currently located throughout Ohio and Illinois.  Approximately 41% of DPLER’s electric sales are also distribution sales of DP&L.  DPLER does not have any transmission or generation assets and all of DPLER’s electric energy was purchased from DP&L 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 our subsidiaries and us.  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  1,197 people as of September 30, 2014, of which 1,142 employees were employed by DP&L.  Approximately 61% of allDPL employees are under a collective bargaining agreement which expires on October 31, 2017.  The current collective bargaining agreement was ratified by the membership on October 30, 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 in an effort to comply, or to determine compliance, with such regulations.  We record liabilities for losses that are probable of occurring and can be reasonably estimated.  See Note 10 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 of Notes to DP&L’s Condensed Financial Statements.

Electric Security Plan 

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for their SSO.  According to Ohio law, 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 SEET based on the earnings of comparable companies with similar business and financial risks. 

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.  An order was issued by the PUCO on September 4, 2013 and a correction to that order was issued on September 6, 2013 (ESP Order).

After several rehearing requests the ESP Order was revised several times.  Collectively the ESP orders state that DP&L’s current ESP began January 2014 and extends through May 31, 2017.  The PUCO authorized DP&L to collect a non-bypassable Service Stability Rider (SSR) equal to $110 million per year for 2014 – 2016.  The ESP Order also directed DP&L to divest its generation assets no later than January 1, 2017 and established DP&L’s SEET threshold at a 12% ROE.  Beginning in 2014, DP&L is no longer permitted to supply 100% of the generation service for SSO customers.  Instead, the PUCO directed DP&L to phase-in the competitive bidding structure with 10% of DP&L’s SSO load sourced through the competitive bid starting in 2014, 60% in 2015, and 100% by January 1, 2016.  The ESP Order approved DP&L’s rate proposal to bifurcate its transmission charges into a non-bypassable component, TCRR-N, and a bypassable component, TCRR-B.  The ESP order also required DP&L to establish a $2.0 million per year shareholder funded economic development fund.

In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets.  Comments and reply comments were filed.  DP&L amended its application on February 25, 2014 and again on May 23, 2014.  Additional comments and reply comments were filed.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.On July 14, 2014, DP&Lpublicly announced its decision not to sell DP&L’s generation assets at this time, but to maintain its plans to transfer or sell the assets in accordance with PUCO orders by January 1, 2017.On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications.   Specifically, DP&L’s request to defer costs associated with OVEC which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets. 

Ohio law and the PUCO agency rules contain targets relating to renewable energy, demand reduction and energy efficiency standards.  If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance.  The PUCO has found that DP&L metits renewable targets for compliance years 2008 – 2012.  PUCO staff recommended that DPLER met its targets for compliance year 2012.  Filing for compliance year 2013 was made on April 15, 2014.  Both DP&L and DPLER are reported to be in full compliance with all renewable targets.  DP&L is also required to meet and has consistently met reliability standards regarding the frequency and duration of outages.  

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On June 13, 2014, Ohio Senate Bill 310 (SB 310) was signed into law and it became effective September 12, 2014.  The new law changes several aspects to renewable energy and energy efficiency sections of law that were created in 2008 referred to as SB 221.  The new law freezes the renewable energy requirements at 2014 levels for 2015 and 2016 and the energy efficiency requirements if a utility modifies its portfolio plan.  The law also removes the advanced energy requirement, and removes the renewable requirement of meeting half of the compliance level through facilities within the state.  DP&L did not file an amended portfolio plan, thereby extending its current plan through 2016.  DP&L recovers the costs of its compliance with Ohio energy efficiency and renewable energy standards through two separate riders.

The ESP Order also provided for the continuation of a fuel and purchased power recovery rider which began January 1, 2010.  The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter: March 1, June 1, September 1 and December 1 each year.  As part of the PUCO approval process, an outside auditor is hired each year to review fuel costs and the fuel procurement process.  On June 12, 2013, we received a report from that external auditor recommending a pre-tax disallowance of $5.3 million of costs.  In August 2014, the PUCO issued an order in a case relating to review of DP&L’s fuel cost recovery mechanism for the calendar year 2012. The order included the disallowance of an immaterial amount of fuel costs. The impact of the order issued was a reversal in the third quarter of a previously established $2.6 million reserve.  

As a member of PJM, DP&L receives revenues from the RTO related to DP&L’s transmission and generation assets and incurs costs associated with its load obligations for retail customers.  Ohio law includes a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits.  DP&L’s TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs.  In accordance with the ESP Order, TCRR-N and TCRR-B began on January 1, 2014.  Both the TCRR-B and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of SSO retail customers’ load and sales volumes to total retail load and total retail and wholesale volumes.  Customer switching to CRES providers decreases DP&L's SSO retail customers’ load and sales volumes.  Therefore, increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.  RPM capacity costs and revenues are discussed further under “Regional Transmission Organizational Risks” in Item 1A – Risk Factors.  DP&L files an annual true-up of TCRR-N and both TCRR-B and RPM are trued up on a seasonal quarterly basis beginning in 2014. 

For calendar year 2012, DP&L was subject to a SEET threshold in which DP&L was required to apply general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings.  Pursuant to an Order issued on February 13, 2014, DP&L’s 2012 earnings were found to not be excessive. Through the ESP Order, the PUCO established DP&L’s ROE SEET threshold at 12% beginning with 2013.  On May 15, 2014, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2013.  A stipulation was reached with the PUCO Staff and filed on July 22, 2014.  A hearing was held on September 9, 2014 and on October 1, 2014 the PUCO issued an order approving the SEET Stipulation.  In future years, the SEET could have a material effect on our results of operations, financial condition and cash flows. 

Other State Regulatory Proceedings

In December 2012 the PUCO announced it was launching an investigation into the health, strength, and vitality of Ohio’s retail electric service market, with the intention of identifying actions the PUCO can take to enhance the market.  There were a series of questions posed for interested parties to comment on in March 2013 and a second set of questions issued in June 2013.  Groups and subgroups were formed to discuss technical aspects of Ohio electric choice and certain enhancements that could be made.  These subgroups met on a weekly basis to discuss issues such as utility purchase of CRES receivables, various billing issues, and portability of CRES contracts, among other topics.  The PUCO issued an order in March 2014 directing Ohio utilities to implement certain billing and system changes to assist competitive suppliers in Ohio.  The PUCO issued an order in May 2014 that overturns some of its previous directions and clarified others.  The outcome of this proceeding presents some changes for billing and systems and it could have a minor impact on DP&L’s operations and how it performs certain functions with respect to Ohio electric choice.

DP&L extended a unique arrangement contract to supply retail electric service to Wright Patterson Air Force Base.  The extension of the contract was filed in July 2014.  This arrangement was approved by the PUCO on October 22, 2014, and the contract will be in place January 1, 2015 through December 31, 2017.

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COMPETITION AND PJM PRICING

RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2017/18 period cleared at a per megawatt price of $120/day for our RTO area. The per megawatt prices for the periods2016/17,2015/16,  2014/15 and 2013/14 were $59/day, $136/day, $126/day and  $28/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 2013, we estimate that a hypothetical increase or decrease of $10/day in the capacity auction price would result in an annual impact to net income of approximately $6.5 million and $5.2 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; however,as discussed above (Electric Security Plan);  the supply of electricity for DP&L’s SSO customers is partially sourced through a competitive bid auction in 2014 and 2015, with 100% sourced through competitive bid starting January 2016.  The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services. 

The following tables provide a summary of the number of electric customers and volumes supplied by DPLER and non-affiliated CRES providers in our service territory during the three and nine months endedSeptember 30, 2014and 2013:

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)
Supplied by DPLER (a)		134,703		1,366		118,458		1,575
Supplied by non-affiliated CRES providers		102,337		1,181		86,359		947
Total in DP&L's service territory		237,040		2,547		204,817		2,522
Distribution customers/sales by DP&L in our service territory (b)		514,371		3,498		513,293		3,618

(a)DPLER’s customer mix has shifted from high-volume industrial consumers to lower volume residential consumers.

(b)The volumes supplied by DPLER represent approximately 39% and 44% of DP&L’s total distribution volumes during the three months endedSeptember 30, 2014 and 2013, 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. 

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	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)
Supplied by DPLER (a)		134,703		4,366		118,458		4,391
Supplied by non-affiliated CRES providers		102,337		3,183		86,359		2,592
Total in DP&L's service territory		237,040		7,549		204,817		6,983
Distribution customers/sales by DP&L in our service territory (b)		514,371		10,588		513,293		10,461

(a)DPLER’s customer mix has shifted from high-volume industrial consumers to lower volume residential consumers.

(b)The volumes supplied by DPLER represent approximately 41% and 42%of DP&L’s total distribution volumes during the nine months endedSeptember 30, 2014 and 2013, 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. 

Lower market prices for power have resulted in increased levels of competition to provide transmission and generation services.  DPLER, an affiliated company and one of the registered CRES providers, has been marketing transmission and generation services to DP&L customers.

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 affect mining costs and supply availability.  Our approach is to hedge the fuel costs for our anticipated electric sales.  For the year ending December 31, 2014, we have substantially all our coal requirements under contract 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				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Revenues:
Retail	$	351.9	$	336.5	$	1,044.9	$	973.1
Wholesale		65.1		73.2		144.8		155.4
RTO revenues		18.5		21.7		64.0		59.5
RTO capacity revenues		41.2		8.4		68.5		20.3
Other revenues		2.6		2.6		8.3		8.2
Other mark-to-market losses		(0.1)		(1.2)		(0.9)		(5.8)
Total revenues		479.2		441.2		1,329.6		1,210.7
Cost of revenues:
Fuel costs		85.3		100.2		236.1		272.0
Losses / (gains) from the sale of coal		(0.3)		(0.4)		(0.4)		1.9
Mark-to-market losses / (gains)		0.1		(0.1)		0.2		0.1
Total fuel		85.1		99.7		235.9		274.0
Purchased power		76.2		71.7		264.8		184.8
RTO charges		37.6		32.2		125.7		84.4
RTO capacity charges		37.9		10.6		68.5		24.2
Mark-to-market losses / (gains)		2.0		(1.4)		7.2		(10.8)
Total purchased power		153.7		113.1		466.2		282.6
Amortization of intangibles		0.3		1.8		0.9		5.3
Total cost of revenues		239.1		214.6		703.0		561.9
Gross margin (a)	$	240.1	$	226.6	$	626.6	$	648.8
Gross margin as a percentage of revenues		50%		51%		47%		54%
Operating income / (loss)	$	90.4	$	76.0	$	10.6	$	191.6

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

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DPL – Revenues

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

	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Heating degree days (a)		81		67		3,902		3,490
Cooling degree days (a)		576		688		968		1,027

(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		Nine months ended
	September 30,		September 30,
$ in millions	2014 vs. 2013		2014 vs. 2013
Retail
Rate	$	48.3	$	84.8
Volume		(32.0)		(15.1)
Other miscellaneous		(0.9)		2.1
Total retail change		15.4		71.8
Wholesale
Rate		(7.7)		(10.6)
Volume		(0.4)		-
Total wholesale change		(8.1)		(10.6)
RTO capacity & other
RTO capacity and other revenues		29.6		52.8
Other
Unrealized MTM		1.1		4.9
Total other revenue		1.1		4.9
Total revenues change	$	38.0	$	118.9

For the three months ended September 30, 2014, Revenues increased $38.0 million to $479.2 million from $441.2 million in the same period of the prior year.  The changes in the components of revenue are discussed below:

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· Retail revenues increased $15.4 million primarily due to a 13% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various regulatory riders for market based costs.  Retail sales volume decreased 7% due to a 16% decrease in cooling degree days during the three months ended September 30, 2014, an  increase in third party switching to CRES providers, and a decrease in sales procured by DPLER and MC Squared.   The above resulted in a favorable $48.3 million retail price variance and an unfavorable $32.0 million retail volume variance.

· Wholesale revenues decreased $8.1 million primarily due to an 11% decrease in average wholesale prices as well as a 12% decrease in generation available from DP&L’s co-owned and operated generation plants.  This resulted in an unfavorable $7.7 million wholesale price variance and an unfavorable wholesale volume variance of $0.4 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased  $29.6 million compared to the same period in 2013.  This increase was primarily a result of a $32.8 million increase in revenues realized from the PJM capacity auction, partially offset by a decrease in RTO transmission and congestion revenues.

For the nine months ended September 30, 2014, Revenues increased $118.9 million to $1,329.6 million from $1,210.7 million in the same period of the prior year.  The changes in the components of revenue are discussed below:

· Retail revenues increased $71.8 million primarily due to an 8% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various regulatory riders for market based costs   Retail sales volumes remained relatively even due to a slight increase in sales procured by DPLER and MC Squared, offset by an increase in switching to third parties.  During the nine months ended September 30, 2014, there was a 12% increase in heating degree days offset by a 6% decrease in cooling degree days; therefore the weather impact is offset on a year to date basis.  The above resulted in a favorable $84.8 million retail price variance and an unfavorable $15.1 million retail volume variance. 

· Wholesale revenues decreased $10.6 million primarily due to a 7% decrease in average wholesale prices. 

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased  $52.8 million compared to the same period in 2013.  This increase was primarily a result of a $48.2 million increase in revenues realized from the PJM capacity auction and an increase of $4.4 million in RTO transmission and congestion revenues.

DPL – Cost of Revenues

For the three months ended September 30, 2014

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $14.6 million, or 15%, compared to the same period in 2013, primarily due to a 12% decrease in generation at our plants along with a 3% decrease in average fuel cost per MWh. 

· Net purchased power increased $40.6 million, or 36%, compared to the same period in 2013 due largely to an increase in RTO capacity charges of $27.3 million and other RTO charges of $5.4 million, as well as increases in the volume of power purchased and price per MWh.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.  RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in 2013.  In addition, net MTM gains in 2013 were losses in 2014, an increase in cost of $3.4 million.

For the nine months ended September 30, 2014: 

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $38.1 million, or 14%, compared to the same period in 2013, primarily due to a  decrease in fuel costs of $35.9 million due to a $6.9 million favorable price variance and a $29.0 million decrease due to reduced volume as a result of an11% decrease in generation at our plants. 

· Net purchased power increased $183.6 million, or 65%, compared to the same period in 2013 due largely to an increase in RTO capacity charges of $44.3 million and other RTO charges of $41.3 million, as well as an increases of 24% in the volume of power purchased and a 15% increase in the price per MWh.  We purchase power to satisfy retail sales volume when generating facilities are not available due 82

to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.  RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in 2013.  In addition, net MTM gains in 2013 were losses in 2014, an increase in cost of $18.0 million.

DPL – Operation and Maintenance

The following table provides a summary of changes in operation and maintenance expense from the prior year periods:

	Three months ended		Nine months ended
	September 30,		September 30,
$ in millions	2014 vs. 2013		2014 vs. 2013
Low-income payment program (a)	$	(3.0)	$	(7.5)
Competitive retail operations		(2.2)		(0.7)
Maintenance of overhead transmission and distribution lines		(0.6)		3.8
Alternative energy and energy efficiency programs (a)		-		3.7
Generating facilities operations and maintenance expense		6.2		2.0
Other, net		(3.7)		(4.0)
Total change in operation and maintenance expense	$	(3.3)	$	(2.7)

(a)There is a corresponding offset in Revenues associated with these programs. 

During the  three months endedSeptember 30, 2014, Operation and maintenance expense decreased $3.3 million, 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,

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

· decreased expenses related to the maintenance of overhead transmission and distribution lines.

These decreases were partially offset by: 

· increased maintenance expenses at our generating facilities.

During the nine months endedSeptember 30, 2014, Operation and maintenance expense decreased $2.7 million, 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 marketing, customer maintenance and labor costs associated with the competitive retail business.

These decreases were partially offset by: 

· increased expenses related to the maintenance of overhead transmission and distribution lines,

· increased expenses relating to alternative energy and energy efficiency programs, and

· increased maintenance expenses at our generating facilities.

DPL – Depreciation and Amortization 

For the three months endedSeptember 30, 2014, Depreciation and amortization expense increased $0.6 million compared to the same period in the prior year as a result of routine plant additions and replacements. 

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For the nine months ended September 30, 2014, Depreciation and amortization expense increased $4.7 million compared to the same period in the prior year as a result of routine plant additions and replacementsand an adjustment of $1.2 million to the AROs for the Hutchings plant. 

DPL – General Taxes 

For the three months ended September 30, 2014, General taxes increased $1.8 million, compared to the same period in the prior year.  The increase was primarily due to a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013 and higher property tax accruals for 2014 compared to 2013.

For the nine months ended September 30, 2014, General taxes increased $9.5 million, compared to the same period in the prior year.  The increase was primarily due to an adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments made in 2014 and higher property tax accruals for 2014 compared to 2013 and a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013.

DPL – Interest Expense

Interest expense recorded during the three months ended September 30, 2014 increased $2.1 million compared to the same period in the prior year.  This was primarily driven by 2013 amortization of a purchase accounting debt premium, which reduced 2013 interest expense by $4.8 million.  Further, there was an increase related to the recovery of previously deferred carrying costs on regulatory assets of $1.9 million.  These were offset by a $4.3 million decrease in bond interest due to the refinancing of certain bonds at a lower interest rate as well as debt prepayments.

Interest expense recorded during the nine months ended September 30, 2014 increased $4.7 million compared to the same period in the prior year.  This was primarily driven by 2013 amortization of a purchase accounting debt premium which reduced 2013 interest expense by $14.4 million.  Further, there was an increase related to the recovery of previously deferred carrying costs on regulatory assets of $3.9 million.  These were offset by an $12.4 million decrease in bond interest due to the refinancing of certain bonds at a lower interest rate as well as debt prepayments.

DPL – Income Tax Expense

For the three months endedSeptember 30, 2014, Income tax expense decreased $52.3 million compared to the same period in 2013, primarily due to the application of an estimated annual effective tax rate (ETR) approach in accordance with ASC 740-270, Interim Reporting, and a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitation on the 2010 tax year.  The 2014 estimated annual ETR is primarily being impacted by the non-deductible goodwill impairment recorded in the first quarter of 2014.

For the nine months ended September 30, 2014, Income tax expense increased $8.9 million compared to the same period in 2013, primarily due to the application of an ETR approach in accordance with ASC 740-270, Interim Reporting.  This increase is partially offset by a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitation on the 2010 tax year.  The ETR for 2014 is estimated to be (42.3)% as compared to the estimated ETR applied to the prior year period of 31.0%.  The primary factor impacting the 2014 ETR is the non-deductible goodwill impairment recorded in the first quarter of 2014.

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RESULTS OF OPERATIONS BY SEGMENT – DPL

DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of 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 DP&L'sSSO customers is primarily generated at seven coal-fired power plants and DP&L distributes electricity to more than 515,000 retail customers.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  By PUCO order DP&L is required to divest its generation assets by January 1, 2017.  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. 

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 274,000 customers currently located throughout Ohio and Illinois.  MC Squared, a Chicago-based retail electricity supplier, serves more than 117,000 customers in Northern Illinois.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.  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 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
	September 30,				Increase /
$ in millions	2014		2013		(Decrease)
Utility	$	218.0	$	206.0	$	12.0
Competitive Retail		12.6		14.1		(1.5)
Other		10.3		7.6		2.7
Adjustments and eliminations		(0.8)		(1.1)		0.3
Total consolidated	$	240.1	$	226.6	$	13.5

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	Nine months ended
	September 30,				Increase /
	2014		2013		(Decrease)
Utility	$	567.8	$	595.2	$	(27.4)
Competitive Retail		34.9		41.1		(6.2)
Other		26.4		15.3		11.1
Adjustments and eliminations		(2.5)		(2.8)		0.3
Total consolidated	$	626.6	$	648.8	$	(22.2)

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.

Income Statement Highlights – Competitive Retail Segment

	Three months ended
	September 30,				Increase /
$ in millions	2014		2013		(Decrease)
Revenues:
Retail	$	140.7	$	140.9	$	(0.2)
RTO and other		0.6		(1.2)		1.8
Total revenues		141.3		139.7		1.6
Cost of revenues:
Purchased power		128.7		125.6		3.1
Gross margins (a)		12.6		14.1		(1.5)
Operation and maintenance expense		7.2		9.5		(2.3)
Other expenses		0.9		0.7		0.2
Total expenses		8.1		10.2		(2.1)
Earnings before income tax		4.5		3.9		0.6
Income tax expense		1.5		1.4		0.1
Net income	$	3.0	$	2.5	$	0.5
Gross margin as a percentage of revenues		9%		10%

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	Nine months ended
	September 30,				Increase /
$ in millions	2014		2013		(Decrease)
Revenues:
Retail	$	414.9	$	387.7	$	27.2
RTO and other		-		(5.8)		5.8
Total revenues		414.9		381.9		33.0
Cost of revenues:
Purchased power		380.0		340.8		39.2
Gross margins (a)		34.9		41.1		(6.2)
Operation and maintenance expense		26.0		26.7		(0.7)
Other expenses		2.6		2.4		0.2
Total expenses		28.6		29.1		(0.5)
Earnings before income tax		6.3		12.0		(5.7)
Income tax expense		2.1		4.3		(2.2)
Net income	$	4.2	$	7.7	$	(3.5)
Gross margin as a percentage of revenues		8%		11%

(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 used by management to make decisions regarding our financial performance.

Competitive Retail Segment – Revenue

For the three months ended September 30, 2014, the segment’s retail revenues increased $1.6 million compared to the same period in 2013 primarily due to increased RTO and other revenue.  The Competitive Retail segment sold approximately 2,498 million kWh of power during the three months ended September 30, 2014 compared to approximately 2,624 million kWh of power during the same period of the prior year.  The Competitive Retail segment had approximately 274,000 and 281,000 customers at September 30, 2014 and 2013, respectively.

For the nine months ended September 30, 2014, the segment’s retail revenues increased $33.0 million, compared to the same period in 2013.  The increase was primarily due to an increase in customer switching to DPLER from outside DP&L’s territory in Ohio, offset by lower retail sales volume from DPLER’s retail customers in DP&L’s service territory and lower customer switching in Illinois.  Also contributing to the increase is higher average retail rates for off-system sales.  The Competitive Retail segment sold approximately 7,614 million kWh of power during the nine months ended September 30, 2014 compared to approximately 7,260 million kWh of power during the same period of the prior year.

Competitive Retail Segment – Purchased Power 

For the three months endedSeptember 30, 2014, the segment’s purchased power increased $3.1 million, or 2%, compared to the same period in 2013 due to higher purchased power prices on the electric energy purchased from DP&L. 

For the nine months endedSeptember 30, 2014, the segment’s purchased power increased $39.2 million, or 12%, compared to the same period in 2013 due to higher purchased power prices and volumes required to meet the demand from an increased customer base resulting from customer switching.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.

Competitive Retail Segment – Operation and Maintenance

For thethree months endedSeptember 30, 2014, DPLER’s operation and maintenance expensesdecreased as a result of decreased sales volume. 

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Competitive Retail Segment – Income Tax Expense

For thethree months endedSeptember 30, 2014, the segment’s income tax expense increased slightly compared to the same period in the prior year due to slightly higher pre-tax income.

For the nine months endedSeptember 30, 2014, the segment’s income tax expense decreased slightly compared to the same period in the prior year due to lower pre-tax income.

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RESULTS OF OPERATIONS – DP&L

Income Statement Highlights – DP&L

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Revenues:
Retail	$	212.2	$	196.5	$	632.5	$	588.1
Wholesale		191.0		189.8		502.8		480.1
RTO revenues		17.8		19.9		60.1		56.6
RTO capacity revenues		34.1		7.0		56.8		17.0
Other mark-to-market gains / (losses)		(0.2)		(0.1)		0.3		(0.3)
Total revenues		454.9		413.1		1,252.5		1,141.5
Cost of revenues:
Fuel costs		84.7		97.2		227.6		267.6
Losses / (gains) from the sale of coal		(0.3)		(0.4)		(0.4)		1.9
Mark-to-market losses / (gains)		0.1		(0.1)		0.2		0.1
Total fuel		84.5		96.7		227.4		269.6
Purchased power		75.3		70.1		260.2		179.9
RTO charges		37.5		30.9		122.0		82.4
RTO capacity charges		37.4		10.6		67.9		23.9
Mark-to-market losses / (gains)		2.2		(1.2)		7.2		(9.5)
Total purchased power		152.4		110.4		457.3		276.7
Total cost of revenues		236.9		207.1		684.7		546.3
Gross margin (a)	$	218.0	$	206.0	$	567.8	$	595.2
Gross margin as a percentage of
revenues		48%		50%		45%		52%
Operating Income	$	75.5	$	64.4	$	126.6	$	162.9

(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 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		Nine months ended
	September 30,		September 30,
$ in millions	2014 vs. 2013		2014 vs. 2013
Retail
Rate	$	41.9	$	76.7
Volume		(25.3)		(33.9)
Other miscellaneous		(0.9)		1.6
Total retail change		15.7		44.4
Wholesale
Rate		5.1		7.3
Volume		(3.9)		15.4
Total wholesale change		1.2		22.7
RTO capacity & other
RTO capacity and other revenues		25.0		43.3
Other
Unrealized MTM		(0.1)		0.6
Total other revenue		(0.1)		0.6
Total revenues change	$	41.8	$	111.0

For the three months endedSeptember 30, 2014, Revenues increased $41.8 million to $454.9 million from $413.1 million in the same period in the prior year.  The changes in the components of revenue are discussed below: 

· Retail revenues increased $15.7 million due to a 25% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various regulatory riders for market based costs.   Retail volumes decreased 13% due to a 25% increase in switching to third party CRES providers; DP&L continues to provide distribution services to those customers, however, the volumes are not recorded.  The above resulted in a favorable $41.9 million retail price variance and an unfavorable $25.3 million retail volume variance. 

· Wholesale revenues increased $1.2 million as a result of a 3% increase in wholesale prices partially  offset by a 2% decrease in wholesale sales volume which was primarily due to an 11% decrease in generation available from DP&L’s co-owned and operated generation plants due higher outages.  These resulted in a favorable $5.1 million wholesale price variance offset by $3.9 million unfavorable wholesale volume variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $25.0 million compared to the same period in 2013.  This increase was primarily the result of an increase in revenues realized from the PJM capacity auction.

For the nine months endedSeptember 30, 2014, Revenues increased $111.0 million to $1,252.5 million from $1,141.5 million in the same period in the prior year.  The changes in the components of revenue are discussed below: 

· Retail revenues increased $44.4 million due to a 14% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various regulatory riders for market based costs.  Retail volume decreased 6% overall mainly due to a 23% increase in switching to third party CRES providers.  DP&L continues to provide distribution services to those customers but the volumes are not recorded.  During the nine months ended September 30, 2014, there was a 12% increase in heating degree days offset by a 6% decrease in cooling degree days; therefore weather was not a factor affecting volume.  The above resulted in a favorable $76.7 million retail price variance offset by an unfavorable $33.9 million retail volume variance.   

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· Wholesale revenues increased $22.7 million as a result of a 3% increase in wholesale sales volume which was largely the result of customer switching.  DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This increase was offset by an 11% decrease in generation available from DP&L’s co-owned and operated generation plants due to lower commercial availability.  Wholesale average rates increased slightly.  The above resulted in a favorable $15.4 million wholesale volume variance and a $7.3 million favorable wholesale price variance. 

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased  $43.3 million compared to the same period in 2013.  This increase was primarily the result of a $39.8 million increase in revenues realized from the PJM capacity auction and an increase of $3.5 million in RTO transmission and congestion revenues.

DP&L – Cost of Revenues 

For the three months endedSeptember 30, 2014: 

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $12.2 million, or 13%, compared to the same period in 2013, primarily due to an11% decrease in generation from our plants.

· Net purchased power increased $42.0 million, or 38%, compared to the same period in 2013 due largely to an increase in RTO capacity charges of $26.8 million and other RTO charges of $6.6 million, as well as increases in the price per MWh.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.  RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in 2013.  In addition, net MTM gains in 2013 were losses in 2014, an increase in cost of $3.4 million.

For the nine months endedSeptember 30, 2014: 

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $42.2 million, or 16%, compared to the same period in 2013, primarily due to an 11% decrease in generation from our plants. 

· Net purchased power increased $180.6 million, or 65%, compared to the same period in 2013 due largely to an increase in purchased power costs of $80.3 million as well as increases in RTO capacity charges of $44.0 million and other RTO charges of $39.6 million.  We had an unfavorable price variance of $36.4 million and an unfavorable volume variance of $43.9 million.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.  RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in 2013.  In addition, net MTM gains in 2013 were losses in 2014, an increase in cost of $16.7 million.

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DP&L – Operation and Maintenance

The following table provides a summary of changes in Operation and maintenance expense from the prior year periods:

	Three months ended		Nine months ended
	September 30,		September 30,
$ in millions	2014 vs. 2013		2014 vs. 2013
Low-income payment program (a)	$	(3.0)	$	(7.5)
Maintenance of overhead transmission and distribution lines		(0.6)		3.8
Group Insurance		(0.5)		(0.9)
Pension and postretirement		(0.4)		(1.2)
Alternative energy and energy efficiency programs (a)		-		3.1
Generating facilities operations and maintenance expense		6.2		2.0
Other, net		(3.4)		(3.8)
Total change in operation and maintenance expense	$	(1.7)	$	(4.5)

(a)There is a corresponding offset in Revenues associated with these programs. 

For the three months endedSeptember 30, 2014, Operation and maintenance expense decreased $1.7 million, 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,

· decreased expenses related to the maintenance of overhead transmission and distribution lines,

· decreased group insurance costs due to reduced headcount partially offset by service company allocations for group insurance, and

· decreased expenses related to pension and postretirement benefits due to updates to actuarial assumptions.

These decreases were partially offset by: 

· increased maintenance expenses at our generating facilities.

For the nine months ended September 30, 2014, Operation and maintenance expense decreased $4.5 million, 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,

· decreased expenses related to pension and postretirement benefits due to updates to actuarial assumptions, and

· decreased group insurance costs due to reduced headcount partially offset by service company allocations for group insurance.

These decreases were partially offset by: 

· increased expenses related to the maintenance of overhead transmission and distribution lines,

· increased expenses relating to alternative energy and energy efficiency programs, and

· increased maintenance expenses at our generating facilities.

DP&L – Depreciation and Amortization 

For the three months endedSeptember 30, 2014, Depreciation and amortization expense increased $0.6 million compared to the same period in the prior year as a result of routine plant additions and replacements partially offset by a reduction in the depreciation expense for the East Bend and Conesville plants as a consequence of the December 2013 impairment write-downs of those two plants. 

For the nine months ended September 30, 2014, Depreciation and amortization expense increased $3.7 million compared to the same period in the prior year as a result of routine plant additions and replacements and an

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adjustment of $1.2 million in the AROs for the Hutchings plant, partially offset by a reduction in the depreciation expense for the East Bend and Conesville plants as a consequence of the December 2013 impairment write-downs of those two plants. 

DP&L – General Taxes 

For the three months endedSeptember 30, 2014, General taxes increased $2.0 million, compared to the same period in the prior year.  The increase was primarily due to a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013and higher property tax accruals for 2014 compared to 2013.

For the nine months ended September 30, 2014, General taxes increased $9.7 million, compared to the same period in the prior year.  The increase was primarily due to an adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments made in 2014 and higher property tax accruals for 2014 compared to 2013 anda favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013.

DP&L – Interest Expense

Interest expense recorded during thethree months endedSeptember 30, 2014decreased $1.0 million compared to the same period in the prior year due to the refinancing of certain bonds at a lower interest rate as well as debt prepayments.

Interest expense recorded during the nine months ended September 30, 2014 decreased $4.2 million compared to the same period in the prior year due to the refinancing of certain bonds at a lower interest rate as well as debt prepayments.

DP&L – Income Tax Expense 

For the three months endedSeptember 30, 2014, Income tax expense decreased $0.1 million compared to the same period in 2013, primarily due to a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitation on the 2010 tax year.

For the nine months ended September 30, 2014, Income tax expense decreased $6.1 million compared to the same period in 2013, primarily due to lower pre-tax income in 2014 and a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitation on the 2010 tax year.

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

Net cash from operating activities 

The revenue from our utility 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.  In addition, positive working capital changes resulted in net cash from operating activities of $174.4 million for the nine months ended September 30, 2014.  This was a $74.7 million decrease compared to the net cash from operating activities for the nine months ended September 30, 2013 and was primarily driven by lower net income adjusted for impairments and the impact of deferred income tax year over year.

Net cash from investing activities

During thenine months endedSeptember 30, 2014 and 2013,Net cash used for investing activities was primarily for capital expenditures at our generation plants.

Net cash from financing activities

During the nine months endedSeptember 30, 2014,  DPL borrowed and repaid $115.0 million from its revolving credit facilities and also repaid $30.0 million on its term loan.  In addition, DP&L borrowed and subsequently repaid $15.0 million from DPL and paid dividends on its preferred stock.

Pension and Postretirement Benefits 

In October 2014, the Society of Actuaries finalized new mortality tables and a new mortality improvement scale.  We are planning to adopt these new mortality tables for the assumptions reflected in our December 31,

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2014 valuation of our pension and postretirement plan obligations and this could have a material impact on our benefit obligation, as well as future benefit costs and contributions.

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.  In2014 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing 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 us to manage working capital requirements during those periods.

At the filing date of this quarterly report on Form 10-Q, DP&Land DPL have access to the following revolving credit facilities:

$ in millions	Type	Maturity	Commitment		Amounts available as of September 30, 2014
DP&L	Revolving	May 2018	$	300.0	$	299.3
DPL	Revolving	May 2018		100.0		97.7
			$	400.0	$	397.0

DP&L’srevolving credit facility, established in May 2013, expires in May 2018 and has nine participating banks, with no bank having more than 22.5% of the total commitment.  This revolving credit facility has a $100.0 million letter of credit sublimit and  DP&L also has the option to increase the potential borrowing amount under this facility by $100.0 million.  At September 30, 2014, there were two letters of credit in the amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L. 

DPL’s revolving credit facility was established in May 2013.  This facility expires in May 2018; however, if DPL has not refinanced its $450.0 million of senior unsecured bonds due October 2016 before July 15, 2016, then this credit facility will expire in July 2016.  This facility has nine participating banks with no bank having more than 20% of the total commitment.  DPL’s revolving credit facility has a $100.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $50.0 million.  As ofSeptember 30, 2014, there was one letter of credit issued in the amount of $2.3 million with the remaining $97.7 million available to DPL.   

Cash and cash equivalents for DPL and DP&L amounted to $104.1 million and $31.0 million, respectively, atSeptember 30, 2014.  At that date, neither DPL nor DP&L had any short-term investments that were not included in cash and cash equivalents. 

Capital Requirements

Planned construction additions for 2014 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 $377.0 million in capital projects for the period 2014 through 2016, of which $355.0 million is projected to be spent by DP&L.  Approximately $5.0 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 $65.0 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

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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

The DPL revolving credit facility and the DPL term loan agreement have a Total Debt to EBITDA ratio that will be 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 in the agreements is not to exceed 8.50 to 1.00 for any fiscal quarter ending June 30, 2013 through December 31, 2014; it then steps down to not exceed 8.00 to 1.00 for any fiscal quarter ending March 31, 2015 through December 31, 2016; and it then steps down not to exceed 7.50 to 1.00 for any fiscal quarter ending March 31, 2017 through March 31, 2018. As of September 30, 2014, the financial covenant was met with a ratio of 6.35 to 1.00. 

The DPL revolving credit facility and the DPL term loan agreement also have an EBITDA to Interest Expense ratio that is calculated at the end of each fiscal quarter by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.  The ratio, per the agreements, is to be net less than 2.00 to 1.00 for any fiscal quarter ending June 30, 2013 through December 31, 2014; it then steps up to be not less than 2.10 to 1.00 for any fiscal quarter ending March 31, 2015 through December 31, 2016; and it then steps up to not to be less than 2.25 to 1.00 for any fiscal quarter ending March 31, 2017 through March 31, 2018.  As of September 30, 2014, this financial covenant was met with a ratio of 2.86 to 1.00. 

DP&L’s revolving credit facility has a financial covenant that requires the Total Debt to Total Capitalization ratio to not exceed 0.65 to 1.00.  As of September 30, 2014, this covenant was met with a ratio of 0.44 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.  In addition, the DP&L revolving credit facility also has an EBITDA to Interest Expense ratio that will be calculated at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. DP&L’s EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. As of September 30, 2014, this covenant was met with a ratio of 10.16 to 1.00.

Debt Ratings

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

	DPL (a)	DP&L (b)	Outlook	Effective
Fitch Ratings	BB	BBB	Stable	September 2014
Moody's Investors Service, Inc.	Ba3	Baa2	Stable	September 2014
Standard & Poor's Financial Services LLC	BB	BBB-	Stable	May 2014

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

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

Credit Ratings

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

	DPL	DP&L	Outlook	Effective
Fitch Ratings	B+	BB+	Stable	September 2014

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Moody's Investors Service, Inc.	Ba3	Baa3	Stable	September 2014
Standard & Poor's Financial Services LLC	BB	BB	Stable	May 2014

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

Off-Balance Sheet Arrangements

DPL – Guarantees

In the normal course of business, DPL enters into various agreements with its wholly owned subsidiaries, DPLE and DPLER, and its wholly owned subsidiary MC Squared, providing financial or performance assurance to third parties.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis,thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes. During the nine months endedSeptember 30, 2014,  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 September 30, 2014,  DPLhad  $19.0 million of guarantees to third parties, for future financial or performance assurance under such agreements, on behalf of DPLER, DPLE and MC Squared.  The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLER, DPLE and MC Squared to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries.  The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.4 million at September 30, 2014. 

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP.  As of September 30, 2014,  DP&L could be responsible for the repayment of 4.9%, or $76.0 million, of a $1,550.1 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 September 30, 2014, 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, 2013. 

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

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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 through the Statement of Operations or, 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 2014 under contract, sales requirements may change.  The majority of the contracted coal is purchased at fixed prices.  Some contracts 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 the counter-party and us at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months. 

A 10% increase or decrease in the market price of our heating oil forwards and FTRs at September 30, 2014 would not have a significant effect on Net income.

At  September 30, 2014,a  10% increase or decrease in the market price of our forward power purchase contracts would result in an impact on unrealized gains/losses of $5.7 million, while a 10% increase or decrease in the market price of our forward power sale contracts would result in an impact on unrealized gains/losses of $9.2 million.

Wholesale Revenues

Energy in excess of the needs of existing retail customers and contracted obligations is sold in the wholesale spot 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				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Percent of electric revenues from wholesale market		22%		18%		16%		15%
DP&L	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Percent of electric revenues from wholesale market		49%		48%		45%		44%

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The following table presents the effect on annual Net income (net of estimated income taxes at 35%)as of September 30, 2014, of a hypothetical increase or decrease of 10% in the price per MWh 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	$	11.3	$	9.0

RPM Capacity Revenues and Costs

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers.  PJM, which has a delivery year that 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 2013/14 through 2017/18are as follows:

	PJM Delivery Year
($/MW-day)	2013/14		2014/15		2015/16		2016/17		2017/18
Capacity clearing price	$	28	$	126	$	136	$	59	$	120

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

	Calendar Year
($/MW-day)	2013		2014		2015		2016		2017
Computed average capacity price	$	23	$	85	$	132	$	91	$	95

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 (net of estimated income taxes at 35%) as of September 30, 2014 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes.  We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO.  These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through September 30, 2014.  As of September 30, 2014, approximately 29% 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	$	6.5	$	5.2

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 nine months ended September 30, 2014 were  38% and 45%,respectively.  We have a significant portion of projected 2014 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 2014 however, the exact consumption of SO₂  allowances will depend on

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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 2014 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, as of September 30, 2014,  SSO customers represent approximately 29% of DP&L’s total fuel costs.

The following table provides the effect on annual Net income (net of estimated income taxes at 35%) as of September 30, 2014, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 29% recovery:

$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	30.2	$	29.4

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 $200.0 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.

In the past,DPL partially hedged against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing activities.  As of September 30, 2014,  DPLhassettled all outstanding interest rate swaps and has no interest rate swaps outstanding.  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 $2,264.4 million at September 30, 2014, 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 September 30, 2014 was $2,345.9 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities.  The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes: 

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DPL
	Principal payments due
	during the twelve months ending												At September 30, 2014
	September 30,												Principal		Fair
$ in millions	2015		2016		2017		2018		2019		Thereafter		Amount		Value
Variable-rate debt	$	10.0	$	40.0	$	40.0	$	70.0	$	-	$	100.0	$	260.0	$	260.0
Average interest rate (a)		2.4%		2.4%		2.4%		2.4%		-		0.1%
Fixed-rate debt	$	0.1	$	445.1	$	430.1	$	0.1	$	0.1	$	1,132.7		2,008.2		2,085.9
Average interest rate		4.2%		1.9%		6.5%		4.2%		4.2%		6.5%
Total													$	2,268.2	$	2,345.9

(a)Based on rates in effect at September 30, 2014

The carrying value of DP&L’sdebt was $877.1 million at September 30, 2014, 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 $884.7 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities.  The following table provides information about DP&L’s debt obligations that are sensitive to interest rate changes.  DP&L’s debt was not revalued as a result of the Merger.

DP&L
	Principal payments due
	during the twelve months ending												At September 30, 2014
	September 30,												Principal		Fair
$ in millions	2015		2016		2017		2018		2019		Thereafter		Amount		Value
Variable-rate debt	$	-	$	-	$	-	$	-	$	-	$	100.0	$	100.0	$	100.0
Average interest rate (a)		-		-		-		-		-		0.1%
Fixed-rate debt	$	0.1	$	445.1	$	0.1	$	0.1	$	0.1	$	332.1		777.6		784.7
Average interest rate		4.2%		1.9%		4.2%		4.2%		4.2%		4.8%
Total													$	877.6	$	884.7

(a)Based on rates in effect at September 30, 2014

Debt maturities occurring in 2014 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 September 30, 2014 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

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expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ.  As of September 30, 2014, we did not hold any market risk sensitive instruments that were entered into for trading purposes.

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 September 30, 2014				One percent
	Carrying		Fair		interest rate
$ in millions	Value		Value		risk
Long-term debt
Variable-rate debt	$	260.0	$	260.0	$	2.6
Fixed-rate debt		2,004.4		2,085.9		20.9
Total	$	2,264.4	$	2,345.9	$	23.5

DP&L	At September 30, 2014				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		777.1		784.7		7.8
Total	$	877.1	$	884.7	$	8.8

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt.  In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $2,085.9 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 $260.0 million variable-rate long-term debt outstanding as of September 30, 2014. 

DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s  $784.7 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 September 30, 2014.

Equity Price Risk

As of September 30, 2014, approximately 18% of the defined benefit pension plan assets were comprised of investments in equity securities and 82% 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 $64.9 million at September 30, 2014.  We believe a hypothetical 10% decrease in prices quoted by stock exchanges during 2014 would  not have any material effect on the 2014 pension expense.  The 2014 pension expense will not change unless an unusual event would occur during 2014 which would require an actuarial re-measurement.  DPL does not foresee an unusual event occurring during 2014 that would require an actuarial re-measurement.  A change in the equity markets could have an effect on 2015 pension expense. 

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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. 

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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits and goodwill and intangible assets.  Refer to our Form 10-K for the fiscal year ended December 31, 2013 for a complete listing of our critical accounting policies and estimates.  There have been no material changes to these critical accounting policies and estimates.

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ELECTRIC SALES AND CUSTOMERS

	DPL				DP&L (a)				DPLER (b)
	Three months ended				Three months ended				Three months ended
	September 30,				September 30,				September 30,
	2014		2013		2014		2013		2014		2013
Electric Sales (millions of kWh)		5,134		5,414		5,112		5,343		2,498		2,624
Billed electric customers (end of period)		653,801		675,592		514,371		513,293		274,133		280,741

(a)This table contains electric sales from DP&L’s generation and purchased power.  DP&L sold 1,367 million kWh and 1,575 million kWh of power to DPLER during the three months ended September 30, 2014 and 2013, 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.

ELECTRIC SALES AND CUSTOMERS

	DPL				DP&L (a)				DPLER (b)
	Nine months ended				Nine months ended				Nine months ended
	September 30,				September 30,				September 30,
	2014		2013		2014		2013		2014		2013
Electric Sales (millions of kWh)		14,352		14,437		14,220		14,312		7,614		7,260
Billed electric customers (end of period)		653,801		675,592		514,371		513,293		274,133		280,741

(a)This table contains electric sales from DP&L’s generation and purchased power.  DP&L sold4,366 million kWh and 4,391 million kWh of power to DPLER during the nine months endedSeptember 30, 2014 and 2013, 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 is communicated to the CEO and CFO.  We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO.  Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective: (i) to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms; and (ii) to ensure that information required to be disclosed by us in the reports that we submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

On May 14, 2013, The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in

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1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We have reviewed the 2013 Framework and integrated the changes into the Company’s internal controls over financial reporting. We expect that management’s assessment of the overall effectiveness of our internal controls over financial reporting for the year ending December 31, 2014 will be based on the 2013 Framework and that the change will not be significant to our overall control structure over financial reporting.There was no change in our internal control over financial reporting during the quarter ended September 30, 2014 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Part II – Other information

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, 2013, and the Notes to DPL’sConsolidated Financial Statements and DP&L’s 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 Form10-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 Form10-K for the fiscal year ended December 31, 2013.  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, as of September 30, 2014,  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.

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

None

Item 3.  Defaults Upon Senior Securities

None

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None

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Item 6.Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X		31(a)	Certification of Chief Executive Officer pursuant to Section302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Section302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to Section302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Section302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to Section906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit32(a)
X		32(b)	Certification of Chief Financial Officer pursuant to Section906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to Section906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to Section906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit32(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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, DPL Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		DPL Inc.
		(Registrant)
Date:	November 5, 2014	/s/ Kenneth J. Zagzebski
		(Kenneth J. Zagzebski)
		President and Chief Executive Officer
		(principal executive officer)
	November 5, 2014	/s/ Craig L. Jackson
		(Craig L. Jackson)
		Chief Financial Officer
		(principal financial officer)
	November 5, 2014	/s/ Kurt A. Tornquist
		(Kurt A. Tornquist)
		Controller
		(principal accounting officer)

108

SIGNATURES

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

		The Dayton Power and Light Company
		(Registrant)
Date:	November 5, 2014	/s/ Derek A. Porter
		(Derek A. Porter)
		President and Chief Executive Officer
		(principal executive officer)
	November 5, 2014	/s/ Craig L. Jackson
		(Craig L. Jackson)
		Chief Financial Officer
		(principal financial officer)
	November 5, 2014	/s/ Kurt A. Tornquist
		(Kurt A. Tornquist)
		Controller
		(principal accounting officer)

109

EX-31.(A)

Exhibit 31(a)

CERTIFICATIONS

I, Kenneth J. Zagzebski, 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: November 5, 2014

/s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

President and Chief Executive Officer

CONFIDENTIALPage 1

EX-31.(B)

Exhibit 31(b)

CERTIFICATIONS

I, Craig L. 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: November 5, 2014

/s/ Craig L. Jackson

Craig L. Jackson

Chief Financial Officer

CONFIDENTIALPage 1

EX-31.(C)

Exhibit 31(c)

CERTIFICATIONS

I, Derek A. Porter, 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: November 5, 2014

/s/ Derek A. Porter

Derek A. Porter

President and Chief Executive Officer

CONFIDENTIALPage 1

EX-31.(D)

Exhibit 31(d)

CERTIFICATIONS

I, Craig L. 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: November 5, 2014

/s/ Craig L. Jackson

Craig L. Jackson

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 November 30, 2014, 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/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

President and Chief Executive Officer

Date: November 5, 2014

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 November 30, 2014, 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

Chief Financial Officer

Date: November 5, 2014

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 November 30, 2014, 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/ Derek A. Porter

Derek A. Porter

President and Chief Executive Officer

Date: November 5, 2014

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 November 30, 2014, 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

Chief Financial Officer

Date: November 5, 2014

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

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Regulatory Matters (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Storm Damage Provision	$ 2.6
Deferred Storm Costs [Member]
Storm Damage Provision	22.3	25.6
DP&L [Member]
Storm Damage Provision	2.6
DP&L [Member] | Deferred Storm Costs [Member]
Storm Damage Provision	$ 22.3	$ 25.6

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Derivative Instruments and Hedging Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Jun. 30, 2014	Sep. 30, 2014 DP&L [Member]	Dec. 31, 2013 Short-term Derivative Positions [Member]	Dec. 31, 2013 Long-term Derivative Positions [Member]
Amount No Longer Considered Derivative		$ 0.1		$ 0.9	$ 0.1
Fair value of commodity derivative instruments	28.0		28.0
Liability position offset by the asset position of counterparties with master netting agreements	9.5		9.5
Collateral Already Posted, Aggregate Fair Value	14.1		14.1
Collateral if debt were to fall below investment grade	$ 4.4		$ 4.4

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Pension and Postretirement Benefits (Net Periodic Benefit Cost (Income)) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013
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			$ 351.0		$ 346.0
Pension [Member]
Service cost	1.5	1.8	4.5		5.4
Interest cost	4.3	3.8	13.1		11.6
Expected return on assets	(5.8)	(5.8)	(17.2)		(17.6)
Actuarial (gain) / loss	0.9	1.3	2.6		3.7
Prior service cost	0.4	0.3	1.1		1.1
Net periodic benefit cost / (income)	1.3	1.4	4.1		4.2
Postretirement [Member]
Service cost			0.1		0.1
Interest cost	0.2	0.2	0.6		0.6
Expected return on assets			(0.1)		(0.2)
Actuarial (gain) / loss	(0.1)	(0.1)	(0.4)		(0.3)
Net periodic benefit cost / (income)	0.1	0.1	0.2		0.2
DP&L [Member]
Market related value of assets			351.0		346.0
DP&L [Member] | Pension [Member]
Service cost	1.5	1.8	4.4		5.4
Interest cost	4.3	3.8	13.0	[1]	11.6	[1]
Expected return on assets	(5.7)	(5.8)	(17.0)		(17.6)
Actuarial (gain) / loss	1.6	2.3	4.8		6.9
Prior service cost	0.7	0.7	2.1		2.1
Net periodic benefit cost / (income)	2.4	2.8	7.3		8.4
DP&L [Member] | Postretirement [Member]
Service cost			0.1		0.1
Interest cost	0.2	0.2	0.6	[1]	0.6	[1]
Expected return on assets	(0.1)	(0.1)	(0.2)		(0.2)
Actuarial (gain) / loss	(0.2)	(0.2)	(0.5)		(0.5)
Prior service cost	0.1	0.1	0.1		0.1
Net periodic benefit cost / (income)			$ 0.1		$ 0.1

[1] 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 ERISA and, in addition, make voluntary contributions from time to time. There were no contributions made during the three and nine months ended September 30, 2014 or 2013, respectively. 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 and nine months ended September 30, 2014 and 2013 was: Net Periodic Benefit Cost / (Income)PensionPostretirementThree months ended Three months ended September 30,September 30,$ in millions2014201320142013Service cost$ 1.5$ 1.8$ -$ -Interest cost 4.3 3.8 0.2 0.2Expected return on plan assets (a) (5.8) (5.8) - -Amortization of unrecognized:Prior service cost 0.4 0.3 - -Actuarial loss / (gain) 0.9 1.3 (0.1) (0.1)Net periodic benefit cost$ 1.3$ 1.4$ 0.1$ 0.1Net Periodic Benefit Cost / (Income)PensionPostretirementNine months ended Nine months ended September 30,September 30,$ in millions2014201320142013Service cost$ 4.5$ 5.4$ 0.1$ 0.1Interest cost 13.1 11.6 0.6 0.6Expected return on plan assets (a) (17.2) (17.6) (0.1) (0.2)Amortization of unrecognized:Prior service cost 1.1 1.1 - -Actuarial loss / (gain) 2.6 3.7 (0.4) (0.3)Net periodic benefit cost$ 4.1$ 4.2$ 0.2$ 0.2For 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 2014 and 2013 net periodic benefit cost was approximately $351 million and $346 million, respectively. Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:$ in millionsPensionPostretirement2014$ 6.3$ 0.52015 23.9 2.12016 23.9 2.02017 24.3 1.82018 24.6 1.62019 - 2023 126.5 6.7

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Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014 MWh	Dec. 31, 2013 MWh
Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	40,700	140,400
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(3,543,000)	(4,705,700)
Derivative, Nonmonetary Notional Amount MWh	(3,502,300)	(4,565,300)
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	40,700	140,400
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(3,543,000)	(4,705,700)
Derivative, Nonmonetary Notional Amount MWh	(3,502,300)	(4,565,300)
Not Designated as Hedging Instrument [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	17,400	7,100
Derivative, Nonmonetary Notional Amount MWh	17,400	7,100
Not Designated as Hedging Instrument [Member] | Commodity Contract - Heating Oil [Member]
Purchase of Volume Units Derivative Instruments Heating Oil Futures	672,000	1,428,000
Derivative, Nonmonetary Notional Amount, Volume	672,000	1,428,000
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	2,320,000	3,177,800
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(3,357,900)	(2,883,100)
Derivative, Nonmonetary Notional Amount MWh	(1,037,900)	294,700
Not Designated as Hedging Instrument [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	17,400	7,100
Derivative, Nonmonetary Notional Amount MWh	17,400	7,100
Not Designated as Hedging Instrument [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Purchase of Volume Units Derivative Instruments Heating Oil Futures	672,000	1,428,000
Derivative, Nonmonetary Notional Amount, Volume	672,000	1,428,000
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	2,320,000	3,172,400
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	(3,463,500)	(2,888,500)
Derivative, Nonmonetary Notional Amount MWh	(1,143,500)	283,900

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Debt Obligations (Long-term Debt Maturities) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Due within one year	$ 110.1
Due within two years	385.1
Due within three years	470.1
Due within four years	70.1
Due within five years	0.1
Thereafter	1,232.7
Total Maturities	2,268.2
Unamortized discounts and premiums, net	3.8
Total	2,264.4
DP&L [Member]
Due within one year	0.1
Due within two years	445.1
Due within three years	0.1
Due within four years	0.1
Due within five years	0.1
Thereafter	432.1
Total Maturities	877.6
Unamortized discounts and premiums, net	(0.5)
Total	$ 877.1

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Summary of Significant Accounting Policies (Related Party Transactions) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Charges for services provided	$ 5.5		$ 27.8
Charges to the Service Company	0.2		0.2
Net Prepaid/Payables to the Service Company	9.4		9.4
DP&L [Member]
Charges for services provided	9.0		28.1
Premiums paid for insurance services provided by MVIC	(0.7)	(0.7)	(2.1)	(2.2)
Expense recoveries for services provided to DPLER	0.5	1.3	1.6	3.8
Deposits received from DPLER	20.1		20.1		19.2
DPLER [Member]
Sales to related party	125.6	123.8	376.6	336.0
Service Company [Member]
Net Prepaid/Payables to the Service Company	$ 9.4		$ 9.4

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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	Sep. 30, 2014	Dec. 31, 2013
Derivative Liability, Fair Value	$ (28.0)
DP&L [Member]
Derivative Liability, Fair Value	(28.0)
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	6.3	4.9
Derivative, Fair Value, Net	0.9	0.7
Derivative, Fair Value, Offset, Net	(5.4)	(4.2)
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	6.5	4.9
Derivative, Fair Value, Net	1.1	0.7
Derivative, Fair Value, Offset, Net	(5.4)	(4.2)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	(10.2)
Derivative, Fair Value, Net	2.0
Derivative, Collateral, net	(2.8)
Derivative, Fair Value, Offset, Net	(5.4)
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	(10.2)	(6.6)
Derivative, Fair Value, Net	2.0	0.1
Derivative, Collateral, net	(2.8)	(2.3)
Derivative, Fair Value, Offset, Net	(5.4)	(4.2)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value		(6.6)
Derivative, Fair Value, Net		0.1
Derivative, Collateral, net		(2.3)
Derivative, Fair Value, Offset, Net		(4.2)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value	(3.4)	(1.3)
Derivative, Fair Value, Net	0.1
Derivative, Collateral, net	(0.7)	(1.0)
Derivative, Fair Value, Offset, Net	(2.6)	(0.3)
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	(3.4)	(1.3)
Derivative, Fair Value, Net	0.1
Derivative, Collateral, net	(0.7)	(1.0)
Derivative, Fair Value, Offset, Net	(2.6)	(0.3)
Not Designated as Hedging Instrument [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value	3.3	5.0
Derivative, Fair Value, Net	0.8	4.7
Derivative, Fair Value, Offset, Net	(2.5)	(0.3)
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	3.6	5.0
Derivative, Fair Value, Net	1.0	4.7
Derivative, Fair Value, Offset, Net	$ (2.6)	$ (0.3)

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Debt Obligations (Tables)

9 Months Ended

Sep. 30, 2014

Long-term Debt

	September 30,		December 31,
$ in millions	2014		2013
First mortgage bonds due in September 2016 - 1.875%	$	445.0	$	445.0
Pollution control series due in January 2028 - 4.7%		36.0		36.0
Pollution control series due in January 2034 - 4.8%		179.6		179.6
Pollution control series due in September 2036 - 4.8%		96.4		96.4
Pollution control series due in November 2040 - rates from: 0.04% - 0.15% and 0.05% - 0.24% (a)		100.0		100.0
U.S. Government note due in February 2061 - 4.2%		18.1		18.3
Unamortized debt discount		(0.5)		(0.7)
Total long-term debt at subsidiary		874.6		874.6
Bank term loan due in May 2018 - rates from: 2.41% - 2.42% and 2.42% - 2.45% (a)		150.0		180.0
Senior unsecured bonds due in October 2016 - 6.5%		330.0		430.0
Senior unsecured bonds due in October 2021 - 7.25%		780.0		780.0
Note to DPL Capital Trust II due in September 2031 - 8.125% (b)		19.7		19.6
Total non-current portion of long-term debt	$	2,154.3	$	2,284.2

Current Portion - Long-term Debt

	September 30,		December 31,
$ in millions	2014		2013
Bank term loan due in May 2018 - rates from: 2.41% - 2.42% and 2.42% - 2.45% (a)	$	10.0	$	10.0
Senior unsecured bonds due in October 2016 - 6.5%		100.0		-
U.S. Government note due in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		-		0.1
Total current portion of long-term debt	$	110.1	$	10.2

Long-term Debt Maturities

Due within the twelve months ending September 30,
($ in millions)
2015	$	110.1
2016		385.1
2017		470.1
2018		70.1
2019		0.1
Thereafter		1,232.7
Total maturities		2,268.2
Unamortized premiums and discounts		(3.8)
Total long-term debt	$	2,264.4

DP&L [Member]

Long-term Debt

	September 30,		December 31,
$ in millions	2014		2013
First mortgage bonds due in September 2016 - 1.875%		445.0		445.0
Pollution control series due in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series due in January 2034 - 4.8%		179.1		179.1
Pollution control series due in September 2036 - 4.8%		100.0		100.0
Pollution control series due in November 2040 - rates from: 0.04% - 0.15% and 0.05% - 0.24% (a)		100.0		100.0
U.S. Government note due in February 2061 - 4.2%		18.1		18.2
Unamortized debt discount		(0.5)		(0.7)
Total non-current portion of long-term debt	$	877.0	$	876.9

Current Portion - Long-term Debt

	September 30,		December 31,
$ in millions	2014		2013
U.S. Government note due in February 2061 - 4.2%		0.1	$	0.1
Capital lease obligations		-		0.1
Total current portion of long-term debt	$	0.1	$	0.2

Long-term Debt Maturities

Due within the twelve months ending September 30,
$ in millions
2015	$	0.1
2016		445.1
2017		0.1
2018		0.1
2019		0.1
Thereafter		432.1
		877.6
Unamortized discounts		(0.5)
Total long-term debt	$	877.1

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Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Long Term Debt Range Adjusted To Fair Value at Merger Start	2016
Long Term Debt Range Adjusted To Fair Value At Merger End	2061
Unrealized gains / (losses) on financial instruments, Amount before tax	$ 0.6	$ 0.9
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax		0.6
Unrealized gains and immaterial unrealized losses in AOCI, after tax	(0.4)
Percent of inputs to the fair value of derivative instruments from quoted market prices	98.00%
Gross additions to our existing landfill and asbestos AROs	1.6
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds	0.6
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax	(0.4)
DP&L [Member]
Long Term Debt Range Adjusted To Fair Value at Merger Start	2016
Long Term Debt Range Adjusted To Fair Value At Merger End	2061
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax	(0.6)	0.7
Unrealized gains and immaterial unrealized losses in AOCI, before tax	0.9	1.2
Percent of inputs to the fair value of derivative instruments from quoted market prices	98.00%
Gross additions to our existing landfill and asbestos AROs	1.7
Available-for-sale Securities, Gross Realized Gains (Losses), Sale Proceeds	0.6
AvailableForSaleSecuritiesGross Realized Gains Losses Sale Proceeds Net of Tax	$ 0.4

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Ownership of Coal-fired Facilities (Ownership Interests) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014 MW
Construction Work in Process	$ 19.0
East Bend Station [Member]
Production Capacity (MW)	186
DP&L [Member]
Construction Work in Process	19.0
DP&L [Member] | Beckjord Unit 6 [Member]
Ownership (%)	50.00%
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] | 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 Investment [Member] | Beckjord Unit 6 [Member]
Gross Plant In Service	2.0
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	24.0
Accumulated Depreciation	1.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | East Bend Station [Member]
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Killen Station [Member]
Gross Plant In Service	309.0
Accumulated Depreciation	17.0
Construction Work in Process	2.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Miami Fort Units 7 and 8 [Member]
Gross Plant In Service	213.0
Accumulated Depreciation	21.0
Construction Work in Process	1.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Stuart Station [Member]
Gross Plant In Service	213.0
Accumulated Depreciation	15.0
Construction Work in Process	12.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Zimmer Station [Member]
Gross Plant In Service	181.0
Accumulated Depreciation	33.0
Construction Work in Process	4.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | Total Jointly-owned Stations [Member]
Gross Plant In Service	984.0
Accumulated Depreciation	93.0
Construction Work in Process	19.0
DP&L Investment [Member] | Transmission (At Varying Percentages) [Member]
Gross Plant In Service	42.0
Accumulated Depreciation	5.0
DP&L Investment [Member] | DP&L [Member] | Beckjord Unit 6 [Member]
Gross Plant In Service	76.0
Accumulated Depreciation	74.0
SCR and FGD Equipment Installed and In Service	No
DP&L Investment [Member] | DP&L [Member] | Conesville Unit 4 [Member]
Gross Plant In Service	22.0
Accumulated Depreciation	3.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | East Bend Station [Member]
Gross Plant In Service	2.0
Accumulated Depreciation	1.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Killen Station [Member]
Gross Plant In Service	624.0
Accumulated Depreciation	311.0
Construction Work in Process	2.0
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	159.0
Construction Work in Process	1.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Stuart Station [Member]
Gross Plant In Service	751.0
Accumulated Depreciation	319.0
Construction Work in Process	12.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L Investment [Member] | DP&L [Member] | Zimmer Station [Member]
Gross Plant In Service	1,100.0
Accumulated Depreciation	670.0
Construction Work in Process	4.0
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	3,034.0
Accumulated Depreciation	1,599.0
Construction Work in Process	19.0
DP&L Investment [Member] | DP&L [Member] | Transmission (At Varying Percentages) [Member]
Gross Plant In Service	98.0
Accumulated Depreciation	$ 62.0

XML

Supplemental Financial Information (Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended			9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 DP&L [Member]	Sep. 30, 2013 DP&L [Member]	Sep. 30, 2014 DP&L [Member]	Sep. 30, 2013 DP&L [Member]	Dec. 31, 2013 DP&L [Member]	Sep. 30, 2014 Available-for-sale Securities [Member]	Dec. 31, 2013 Available-for-sale Securities [Member]	Sep. 30, 2014 Available-for-sale Securities [Member] DP&L [Member]	Dec. 31, 2013 Available-for-sale Securities [Member] DP&L [Member]	Sep. 30, 2014 Derivative [Member]	Dec. 31, 2013 Derivative [Member]	Sep. 30, 2014 Derivative [Member] DP&L [Member]	Dec. 31, 2012 Derivative [Member] DP&L [Member]	Sep. 30, 2014 Other Pension Plan, Defined Benefit [Member]	Dec. 31, 2013 Other Pension Plan, Defined Benefit [Member]	Sep. 30, 2014 Other Pension Plan, Defined Benefit [Member] DP&L [Member]	Dec. 31, 2013 Other Pension Plan, Defined Benefit [Member] DP&L [Member]
Total Reclassifications out of AOCI	$ 3.6	$ 1.7	$ 14.6	$ 4.7		$ 4.1	$ 2.3	$ 17.8	$ 6.4		$ 0.4		$ 0.4		$ 14.2		$ 15.3				$ 2.1
Total Adjustments to AOCI			(24.4)					(26.9)			(0.6)		(0.6)		(23.8)		(26.3)
Other Comprehensive Income (Loss), Net of Tax	4.4	8.1	(9.8)	22.1				(9.1)			(0.2)		(0.2)		(9.6)		(11.0)				2.1
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 14.8		$ 14.8		$ 24.6	$ (35.8)		$ (35.8)		$ (26.7)	$ 0.4	$ 0.6	$ 0.6	$ 0.8	$ 11.0	$ 20.6	$ (4.8)	$ 6.2	$ 3.4	$ 3.4	$ (31.6)	$ (33.7)

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
DP&L [Member]
Total Master Trust Assets, Fair Value	$ 10.0	$ 11.5
Total Derivative Assets	11.7	13.8
Total Assets	21.7	25.3
Debt Instrument, Fair Value Disclosure	884.7	859.6
Total Derivative Liabilities	28.0	10.6
Total Liabilities	912.7	870.2
DP&L [Member] | Forward Contract Power [Member]
Total Derivative Assets	11.7	13.4
Total Derivative Liabilities	26.9	10.6
DP&L [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	1.0
DP&L [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0.1
Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	10.0	11.5
Total Derivative Assets	11.2	13.8
Total Assets	21.2	25.3
Total Derivative Liabilities	28.0	10.6
Total Liabilities	2,373.9	2,345.2
Estimate of Fair Value, Fair Value Disclosure [Member] | Forward Contract Power [Member]
Total Derivative Assets	11.2	13.4
Total Derivative Liabilities	26.9	10.6
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	1.0
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0.1
Level 1 [Member]
Total Master Trust Assets, Fair Value	9.1	10.6
Total Derivative Assets		0.2
Total Assets	9.1	10.8
Total Derivative Liabilities	0.1
Total Liabilities	0.1
Level 1 [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0.1
Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	9.1	10.6
Total Derivative Assets		0.2
Total Assets	9.1	10.8
Total Derivative Liabilities	0.1
Total Liabilities	0.1
Level 1 [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	0.1
Level 2 [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Total Derivative Assets	11.2	13.4
Total Assets	12.1	14.3
Total Derivative Liabilities	26.9	10.6
Total Liabilities	2,354.5	2,326.7
Level 2 [Member] | Forward Contract Power [Member]
Total Derivative Assets	11.2	13.4
Total Derivative Liabilities	26.9	10.6
Level 2 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Total Derivative Assets	11.7	13.4
Total Assets	12.6	14.3
Debt Instrument, Fair Value Disclosure	866.4	841.1
Total Derivative Liabilities	26.9	10.6
Total Liabilities	893.3	851.7
Level 2 [Member] | DP&L [Member] | Forward Contract Power [Member]
Total Derivative Assets	11.7	13.4
Total Derivative Liabilities	26.9	10.6
Level 3 [Member]
Total Derivative Assets		0.2
Total Assets		0.2
Total Derivative Liabilities	1.0
Total Liabilities	19.3	18.5
Level 3 [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	1.0
Level 3 [Member] | DP&L [Member]
Total Derivative Assets		0.2
Total Assets		0.2
Debt Instrument, Fair Value Disclosure	18.3	18.5
Total Derivative Liabilities	1.0
Total Liabilities	19.3	18.5
Level 3 [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Total Derivative Assets		0.2
Total Derivative Liabilities	1.0
Equity Securities [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	3.6	4.4
Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	3.6	4.4
Equity Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	3.6	4.4
Equity Securities [Member] | Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	3.6	4.4
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	3.6	4.4
Debt Securities [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	5.0	5.5
Debt Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.0	5.5
Debt Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	5.0	5.5
Debt Securities [Member] | Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	5.0	5.5
Money Market Funds [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.1	0.3
Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.1	0.3
Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.1	0.3
Money Market Funds [Member] | Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.1	0.3
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.1	0.3
Debt [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Debt Instrument, Fair Value Disclosure	2,345.9	2,334.6
Debt [Member] | Level 2 [Member]
Debt Instrument, Fair Value Disclosure	2,327.6	2,316.1
Debt [Member] | Level 3 [Member]
Debt Instrument, Fair Value Disclosure	18.3	18.5
Debt [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	5.0	5.5
Hedge Funds [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Hedge Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Hedge Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Hedge Funds [Member] | Level 2 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Real Estate Funds [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Real Estate Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Real Estate Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Real Estate Funds [Member] | Level 1 [Member] | DP&L [Member]
Total Master Trust Assets, Fair Value	0.4	0.4
Real Estate Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	$ 0.4	$ 0.4

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Business Segments (Narrative) (Details)	9 Months Ended
	Sep. 30, 2014 sqmi
Service area, square miles	6,000
Number of coal fired power plants	7
Approximate number of retail customers	515,000
Approximate Number Of Competitive Retail Customers	274,000
Electric generation through competitive bid	10.00%
Number of MC Squared Retail Customers	117,000
DP&L [Member]
Service area, square miles	6,000
Approximate number of retail customers	515,000

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Income Taxes (Narrative) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Estimated annual effective income tax rate			(42.30%)	31.00%
Effective income tax rates	(71.50%)	25.40%	(34.20%)	21.50%
DP&L [Member]
Estimated annual effective income tax rate			30.50%	29.50%
Effective income tax rates	19.80%	24.40%	23.20%	22.50%

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Regulatory Matters

9 Months Ended

Sep. 30, 2014

Regulatory Matters

3.  Regulatory Assets 

DP&L’s regulatory asset for deferred storm costs represents costs incurred to repair the damage caused to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. Such costs are included in Regulatory assets, non-current on the accompanying Condensed Consolidated Balance Sheets and were $22.3 million and $25.6 million as of September 30, 2014 and December 31, 2013, respectively. DP&L filed an application with the PUCO in 2012 to recover these costs.  The main issue in the case was the level of storm costs that should be recoverable. On April 14, 2014, DP&L reached an agreement in principle with the PUCO Staff whereby DP&L would recover storm costs of $22.3 million from all customers on a non-bypassable basis.  As a result of these developments, we reduced the regulatory asset balance to $22.3 million as our best estimate of the amount that is probable of recovery.  In accordance with FASC 980 “Regulated Operations”, the reduction was recognized as a current period expense, which is included in Operation and maintenanceand the corresponding adjustment to carrying costs which is included in interest expense on the accompanying Condensed Consolidated Statements of Results of Operations.  A stipulation was finalized and filed at the PUCO and a hearing took place the first week of June 2014.  A decision is expected before the end of the year.

In August 2014, the PUCO issued an order in a case relating to review of DP&L’s fuel cost recovery mechanism for the calendar year 2012. The order included the disallowance of an immaterial amount of fuel costs. The impact of the order issued was a reversal in the third quarter of a previously established$2.6 million reserve.

DP&L [Member]

Regulatory Matters

3.  Regulatory Assets 

DP&L’s regulatory asset for deferred storm costs represents costs incurred to repair the damage caused to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. Such costs are included in Regulatory Assets, non-current on the accompanying Condensed Balance Sheets and were $22.3 million and $25.6 million as of March 31, 2014 and December 31, 2013, respectively. DP&L filed an application with the PUCO in 2012 to recover these costs.  The main issue in the case was the level of storm costs that should be recoverable. On April 14, 2014, DP&L reached an agreement in principle with the PUCO Staff whereby DP&L would recover storm costs of $22.3 million from all customers on a non-bypassable basis.  As a result of these developments, we reduced the regulatory asset balance to $22.3 million as our best estimate of the amount that is probable of recovery.  In accordance with FASC 980 “Regulated Operations”, the reduction was recognized as a current period expense, which is included in Operation and maintenanceand the corresponding adjustment to carrying costs which is included in interest expense on the accompanying Condensed Statements of Results of Operations.  A stipulation was finalized and filed at the PUCO and a hearing took place the first week of June 2014.  A decision is expected before the end of the year. 

In August 2014, the PUCO issued an order in a case relating to review of DP&L’s fuel cost recovery mechanism for the calendar year 2012. The order included the disallowance of an immaterial amount of fuel costs. The impact of the order issued was a reversal in the third quarter of a previously established$2.6 million reserve.

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Business Segments (Segment Financial Information) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Intersegment revenues	$ 0.2			$ 0.2
Total revenues	479.2		441.2	1,329.6	1,210.7
Fuel Costs	85.1		99.7	235.9	274.0
Purchased power	153.7		113.1	466.2	282.6
Amortization of intangibles				0.9	5.3
Gross margin	240.1		226.6	626.6	648.8
Depreciation and amortization	34.5		33.9	103.7	99.0
Goodwill, Impairment Loss		135.8		135.8
Fixed asset impairment				11.5
Interest expense	33.1		31.0	95.8	91.1
Income tax expense (benefit)	(41.0)		11.3	29.7	20.8
Net income (loss)	98.4		33.2	(116.8)	76.0
Total Assets	3,542.6			3,542.6		3,721.5
Utility [Member]
External customer revenues	329.3		289.3	875.9	805.5
Intersegment revenues	125.6		123.8	376.6	336.0
Total revenues	454.9		413.1	1,252.5	1,141.5
Fuel Costs	84.5		96.7	227.4	269.6
Purchased power	152.4		110.4	457.3	276.7
Gross margin	218.0		206.0	567.8	595.2
Depreciation and amortization	36.4		35.8	108.2	104.5
Interest expense	9.4		10.4	25.5	29.7
Income tax expense (benefit)	13.1		13.2	23.1	29.2
Net income (loss)	53.2		40.9	76.5	101.4
Capital expenditures	25.6		28.3	78.6	95.1
Total Assets	3,245.3			3,245.3		3,313.1
Competitive Retail [Member]
External customer revenues	141.3		139.7	414.9	381.9
Total revenues	141.3		139.7	414.9	381.9
Purchased power	128.7		125.6	380.0	340.8
Gross margin	12.6		14.1	34.9	41.1
Depreciation and amortization	0.3		0.1	0.6	0.4
Interest expense	0.1		0.1	0.3	0.4
Income tax expense (benefit)	1.5		1.4	2.1	4.3
Net income (loss)	3.0		2.5	4.2	7.7
Capital expenditures	0.5			0.5
Total Assets	100.3			100.3		105.0
Other Reportable Business Segment [Member]
External customer revenues	8.6		12.2	38.8	23.3
Intersegment revenues	3.0		1.0	4.1	3.0
Total revenues	11.6		13.2	42.9	26.3
Fuel Costs	0.6		2.9	8.5	4.2
Purchased power	0.4		0.9	7.1	1.5
Amortization of intangibles	0.3		1.8	0.9	5.3
Gross margin	10.3		7.6	26.4	15.3
Depreciation and amortization	(2.2)		(2.0)	(5.1)	(5.9)
Goodwill, Impairment Loss				135.8
Fixed asset impairment				11.5
Interest expense	23.8		20.6	70.5	61.5
Income tax expense (benefit)	(55.6)		(3.3)	4.5	(12.7)
Net income (loss)	42.2		(10.2)	(197.5)	(33.1)
Capital expenditures	0.3		1.0	2.5	1.4
Total Assets	1,536.9			1,536.9		1,675.8
Adjustments and Eliminations [Member]
Intersegment revenues	(128.6)		(124.8)	(380.7)	(339.0)
Total revenues	(128.6)		(124.8)	(380.7)	(339.0)
Fuel Costs			0.1		0.2
Purchased power	(127.8)		(123.8)	(378.2)	(336.4)
Gross margin	(0.8)		(1.1)	(2.5)	(2.8)
Interest expense	(0.2)		(0.1)	(0.5)	(0.5)
Total Assets	(1,339.9)			(1,339.9)		(1,372.4)
Parent Company [Member]
External customer revenues	479.2		441.2	1,329.6	1,210.7
Total revenues	479.2		441.2	1,329.6	1,210.7
Fuel Costs	85.1		99.7	235.9	274.0
Purchased power	153.7		113.1	466.2	282.6
Amortization of intangibles	0.3		1.8	0.9	5.3
Gross margin	240.1		226.6	626.6	648.8
Depreciation and amortization	34.5		33.9	103.7	99.0
Goodwill, Impairment Loss				135.8
Fixed asset impairment				11.5
Interest expense	33.1		31.0	95.8	91.1
Income tax expense (benefit)	(41.0)		11.3	29.7	20.8
Net income (loss)	98.4		33.2	(116.8)	76.0
Capital expenditures	26.4		29.3	81.6	96.5
Total Assets	$ 3,542.6			$ 3,542.6		$ 3,721.5

XML

Debt Obligations (Narrative) (Details) (USD $)	9 Months Ended							9 Months Ended			9 Months Ended		9 Months Ended			9 Months Ended	4 Months Ended		9 Months Ended					9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended			9 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 DP&L [Member]	Mar. 31, 2014 DP&L [Member]	Dec. 31, 2013 DP&L [Member]	Oct. 20, 2014 DPL [Member] Cash on hand [Member] Subsequent Event [Member]	Sep. 30, 2014 DPL [Member] Credit Facility [Member]	Oct. 06, 2014 Senior Unsecured notes maturing October 2019 at 6.75% [Member] DPL [Member] Subsequent Event [Member]	Sep. 30, 2014 Senior Unsecured notes maturing October 2019 at 6.75% [Member] DPL [Member] Subsequent Event [Member]	Sep. 30, 2014 U.S. Government note maturing in February 2061 - 4.20% [Member]	Dec. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member]	Sep. 30, 2014 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Dec. 31, 2013 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Mar. 31, 2014 Related Party Notes Payable [Member]	Sep. 30, 2014 Revolving Credit Agreeement with Bank Group Expiring 2018 [Member]	May 10, 2013 Revolving Credit Agreeement with Bank Group Expiring 2018 [Member] DP&L [Member]	Sep. 30, 2014 Revolving Credit Agreeement with Bank Group Expiring 2018 [Member] DP&L [Member]	Sep. 30, 2014 Revolving Credit Agreeement with Bank Group Expiring 2018 [Member] DPL [Member]	Sep. 30, 2014 Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Dec. 31, 2013 Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Sep. 06, 2014 Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member] DPL [Member] Scenario, Forecast [Member]	Oct. 06, 2014 Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member] DPL [Member] Tender offer [Member] Subsequent Event [Member]	Sep. 30, 2014 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Dec. 31, 2013 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Sep. 30, 2014 First Mortgage Bonds Maturing in September 2016	Dec. 31, 2013 First Mortgage Bonds Maturing in September 2016	Sep. 30, 2014 First Mortgage Bonds Maturing in September 2016 DP&L [Member]	Dec. 31, 2013 First Mortgage Bonds Maturing in September 2016 DP&L [Member]	Sep. 30, 2014 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Dec. 31, 2013 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Sep. 30, 2014 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member] Subsequent Event [Member]	Sep. 30, 2014 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Dec. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]	Sep. 30, 2014 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Dec. 31, 2013 Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] DP&L [Member]	Sep. 30, 2014 Bank Term Loan maturing in May 2018 [Member]	Dec. 31, 2013 Bank Term Loan maturing in May 2018 [Member]
Debt Instrument, Face Amount							$ 100,000,000		$ 200,000,000													$ 280,000,000	$ 300,000,000
Repurchase of Securities at Fair Value																																5,000,000
Additional principal amount of senior notes to be raised	1,250,000,000																			450,000,000				800,000,000
Debt Instrument, Maturity Date Range, End											Feb. 01, 2061		Feb. 01, 2061							Oct. 01, 2016				Oct. 01, 2021		Sep. 01, 2016		Sep. 01, 2016		Sep. 01, 2031			Nov. 01, 2040		Nov. 01, 2040		May 01, 2018
Notes Payable, Related Parties					15,000,000
Unsecured revolving credit agreement																	300,000,000	300,000,000	100,000,000
Withdrawals from revolving credit facilities	115,000,000	50,000,000
Increase/decrease additional facility																100,000,000	100,000,000		100,000,000
Letter of credit sublimit																100,000,000	100,000,000		100,000,000
Letters of credit outstanding								2,300,000										700,000
Line of Credit Facility, Remaining Borrowing Capacity								97,700,000										299,300,000
Long-term Debt, Gross											(18,100,000)	(18,300,000)	18,100,000	18,200,000						330,000,000	430,000,000			780,000,000	780,000,000	445,000,000	445,000,000	445,000,000	445,000,000	19,700,000	19,600,000		100,000,000	100,000,000	100,000,000	100,000,000	150,000,000	180,000,000
Premium Expenses																				1,900,000				500,000
Current portion - long-term debt	110,100,000		10,200,000	100,000		200,000														100,000,000
Repayments of debt								$ 50,000,000												$ 20,000,000				$ 20,000,000
Debt instrument interest percentage										6.75%	4.20%		4.20%		2.00%					6.50%				7.25%		1.875%		1.875%		8.125%

XML

Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 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		17.4		-		17.4
Heating oil futures		Mark to Market	Gallons		672.0		-		672.0
Forward power contracts		Cash Flow Hedge	MWh		40.7		(3,543.0)		(3,502.3)
Forward power contracts		Mark to Market	MWh		2,320.0		(3,357.9)		(1,037.9)

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		7.1		-		7.1
Heating oil futures		Mark to Market	Gallons		1,428.0		-		1,428.0
Forward power contracts		Cash Flow Hedge	MWh		140.4		(4,705.7)		(4,565.3)
Forward power contracts		Mark to Market	MWh		3,177.8		(2,883.1)		294.7

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(12.4)	$	18.8	$	(1.1)	$	12.8
Net gains / (losses) associated with current period hedging transactions		1.2		-		(0.2)		6.4
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.2)		-		-
Revenues		3.4		-		0.3		-
Purchased power		0.2		-		1.0		-
Ending accumulated derivative gain / (loss) in AOCI	$	(7.6)	$	18.6	$	-	$	19.2

	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	1.4	$	19.2	$	(3.0)	$	0.5
Net gains / (losses) associated with current period hedging transactions		(23.8)		-		-		18.7
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.6)		-		-
Revenues		15.4		-		1.3		-
Purchased power		(0.6)		-		1.7		-
Ending accumulated derivative gain / (loss) in AOCI	$	(7.6)	$	18.6	$	-	$	19.2
Portion expected to be reclassified to earnings in the next twelve months (a)	$	(7.3)	$	(0.6)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		27		0

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

For the three months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.3	$	(2.3)	$	(2.2)
Realized gain / (loss)		-		0.1		(2.1)		(2.0)
Total	$	(0.2)	$	0.4	$	(4.4)	$	(4.2)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Purchased power		-		0.4		(4.4)		(4.0)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	0.4	$	(4.4)	$	(4.2)

For the three months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain	$	0.1	$	1.3	$	0.1	$	1.5
Realized gain / (loss)		0.1		-		(0.8)		(0.7)
Total	$	0.2	$	1.3	$	(0.7)	$	0.8
Recorded in Income Statement: gain / (loss)
Purchased power	$	-	$	1.3	$	(0.7)	$	0.6
Fuel		0.1		-		-		0.1
O&M		0.1		-		-		0.1
Total	$	0.2	$	1.3	$	(0.7)	$	0.8

For the nine months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized loss	$	(0.3)	$	(1.2)	$	(6.0)	$	(7.5)
Realized gain / (loss)		0.1		0.7		(3.6)		(2.8)
Total	$	(0.2)	$	(0.5)	$	(9.6)	$	(10.3)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: loss
Purchased power		-		(0.5)		(9.6)		(10.1)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	(0.5)	$	(9.6)	$	(10.3)

For the nine months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.4	$	10.5	$	10.7
Realized gain		-		1.2		0.5		1.7
Total	$	(0.2)	$	1.6	$	11.0	$	12.4
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Purchased power		-		1.6		11.0		12.6
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	1.6	$	11.0	$	12.4

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

Fair Values of Derivative Instruments
at September 30, 2014
				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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.9	$	(0.9)	$	-	$	-
Forward power contracts	MTM		6.3		(5.4)		-		0.9
Heating oil	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.7		(0.6)		(0.1)		-
Forward power contracts	MTM		3.3		(2.5)		-		0.8
Total assets		$	11.2	$	(9.4)	$	(0.1)	$	1.7
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	12.0	$	(0.9)	$	(9.8)	$	1.3
Forward power contracts	MTM		10.2		(5.4)		(2.8)		2.0
Heating oil	MTM		0.1		-		(0.1)		-
FTRs	MTM		1.0		-		-		1.0
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.3		(0.6)		(0.7)		-
Forward power contracts	MTM		3.4		(2.6)		(0.7)		0.1
Total liabilities		$	28.0	$	(9.5)	$	(14.1)	$	4.4

Fair Values of Derivative Instruments
at December 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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2		-		-		0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

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		17.4		-		17.4
Heating oil futures		Mark to Market	Gallons		672.0		-		672.0
Forward power contracts		Cash Flow Hedge	MWh		40.7		(3,543.0)		(3,502.3)
Forward power contracts		Mark to Market	MWh		2,320.0		(3,463.5)		(1,143.5)

Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		7.1		-		7.1
Heating oil futures		Mark to Market	Gallons		1,428.0		-		1,428.0
Forward power contracts		Cash Flow Hedge	MWh		140.4		(4,705.7)		(4,565.3)
Forward power contracts		Mark to Market	MWh		3,172.4		(2,888.5)		283.9

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(14.0)	$	4.6	$	(1.9)	$	6.1
Net gains / (losses) associated with current period hedging transactions		1.4		-		(0.3)		-
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.2)		-		(0.6)
Revenues		3.2		-		0.3		-
Purchased power		0.2		-		1.3		-
Ending accumulated derivative gain / (loss) in AOCI	$	(9.2)	$	4.4	$	(0.6)	$	5.5

	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	1.0	$	5.2	$	(4.7)	$	7.3
Net losses associated with current period hedging transactions		(26.3)		-		-		-
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.8)		-		(1.8)
Revenues		16.6		-		1.4		-
Purchased power		(0.5)		-		2.7		-
Ending accumulated derivative gain / (loss) in AOCI	$	(9.2)	$	4.4	$	(0.6)	$	5.5
Portion expected to be reclassified to earnings in the next twelve months (a)	$	(7.2)	$	(1.1)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		27		0

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

For the three months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.3	$	(2.7)	$	(2.6)
Realized gain / (loss)		-		0.1		(2.1)		(2.0)
Total	$	(0.2)	$	0.4	$	(4.8)	$	(4.6)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		(0.3)		(0.3)
Purchased power		-		0.4		(4.5)		(4.1)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	0.4	$	(4.8)	$	(4.6)

For the three months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	0.1	$	1.3	$	(0.1)	$	1.3
Realized gain / (loss)		0.1		-		(0.8)		(0.7)
Total	$	0.2	$	1.3	$	(0.9)	$	0.6
Recorded in Income Statement: gain / (loss)
Revenues	$	-	$	-	$	0.1	$	0.1
Purchased power		-		1.3		(1.0)		0.3
Fuel		0.1		-		-		0.1
O&M		0.1		-		-		0.1
Total	$	0.2	$	1.3	$	(0.9)	$	0.6

For the nine months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized loss	$	(0.3)	$	(1.2)	$	(5.7)	$	(7.2)
Realized gain / (loss)		0.1		0.7		(3.0)		(2.2)
Total	$	(0.2)	$	(0.5)	$	(8.7)	$	(9.4)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		1.0		1.0
Purchased power		-		(0.5)		(9.7)		(10.2)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	(0.5)	$	(8.7)	$	(9.4)

For the nine months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.4	$	8.9	$	9.1
Realized gain		-		1.2		1.1		2.3
Total	$	(0.2)	$	1.6	$	10.0	$	11.4
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		0.2		0.2
Purchased power		-		1.6		9.8		11.4
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	1.6	$	10.0	$	11.4

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

Fair Values of Derivative Instruments
at September 30, 2014
				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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.9	$	(0.9)	$	-	$	-
Forward power contracts	MTM		6.5		(5.4)		-		1.1
Heating oil futures	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.7		(0.6)		(0.1)		-
Forward power contracts	MTM		3.6		(2.6)		-		1.0
Total assets		$	11.7	$	(9.5)	$	(0.1)	$	2.1
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	12.0	$	(0.9)	$	(9.8)	$	1.3
Forward power contracts	MTM		10.2		(5.4)		(2.8)		2.0
Heating oil futures	MTM		0.1		-		(0.1)		-
FTRs	MTM		1.0		-		-		1.0
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.3		(0.6)		(0.7)		-
Forward power contracts	MTM		3.4		(2.6)		(0.7)		0.1
Total liabilities		$	28.0	$	(9.5)	$	(14.1)	$	4.4

Fair Values of Derivative Instruments
at December 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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2						0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

XML

Fair Value Measurements (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2014

Dec. 31, 2013

Fair Value and Cost of Non-Derivative Instruments

	September 30, 2014				December 31, 2013
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.6		3.3		4.4
Debt securities		5.0		5.0		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total Assets	$	9.0	$	10.0	$	10.3	$	11.5
Liabilities
Debt	$	2,264.4	$	2,345.9	$	2,294.4	$	2,334.6

Fair Value of Assets and Liabilities Measured on Recurring Basis

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.1	$	0.1	$	-	$	-
Equity securities		3.6		3.6		-		-
Debt securities		5.0		5.0		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		10.0		9.1		0.9		-
Derivative Assets
Forward power contracts		11.2		-		11.2		-
Total Derivative assets		11.2		-		11.2		-
Total Assets	$	21.2	$	9.1	$	12.1	$	-
Liabilities
Derivative Liabilities
FTRs	$	1.0	$	-	$	-	$	1.0
Heating oil		0.1		0.1		-		-
Forward power contracts		26.9		-		26.9		-
Total Derivative liabilities		28.0		0.1		26.9		1.0
Long-term debt		2,345.9		-		2,327.6		18.3
Total Liabilities	$	2,373.9	$	0.1	$	2,354.5	$	19.3

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		11.5		10.6		0.9		-
Derivative assets
FTRs		0.2		-		-		0.2
Heating oil futures		0.2		0.2		-		-
Forward power contracts		13.4		-		13.4		-
Total Derivative assets		13.8		0.2		13.4		0.2
Total Assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Derivative liabilities
Forward power contracts	$	10.6	$	-		10.6	$	-
Total Derivative liabilities		10.6		-		10.6		-
Long-term debt		2,334.6		-		2,316.1		18.5
Total Liabilities	$	2,345.2	$	-	$	2,326.7	$	18.5

Fair Value Measurements, Nonrecurring [Table Text Block]

$ in millions	Nine months ended September 30, 2014
		Carrying	Fair Value							Gross
		Amount (c)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (East Bend)	$	14.2	$	-	$	-	$	2.7	$	11.5
Goodwill (b)
DPLER Reporting unit	$	135.8	$	-	$	-	$	-	$	135.8

DP&L [Member]

Fair Value and Cost of Non-Derivative Instruments

	September 30, 2014				December 31, 2013
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.6		3.3		4.4
Debt securities		5.0		5.0		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total assets	$	9.0	$	10.0	$	10.3	$	11.5
Liabilities
Debt	$	877.1	$	884.7	$	877.1	$	859.6

Fair Value of Assets and Liabilities Measured on Recurring Basis

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.1	$	0.1	$	-	$	-
Equity securities		3.6		3.6		-		-
Debt securities		5.0		5.0		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		10.0		9.1		0.9		-
Derivative assets
FTRs		-		-		-		-
Heating oil		-		-		-		-
Forward power contracts		11.7		-		11.7		-
Total derivative assets		11.7		-		11.7		-
Total assets	$	21.7	$	9.1	$	12.6	$	-
Liabilities
Derivative liabilities
FTRs	$	1.0	$	-	$	-	$	1.0
Heating oil		0.1		0.1		-		-
Forward power contracts		26.9		-		26.9		-
Total derivative liabilities		28.0		0.1		26.9		1.0
Long-term debt		884.7		-		866.4		18.3
Total liabilities	$	912.7	$	0.1	$	893.3	$	19.3

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		11.5		10.6		0.9		-
Derivative assets
Heating oil futures		0.2		0.2		-		-
FTRs		0.2		-		-		0.2
Forward power contracts		13.4		-		13.4		-
Total Derivative assets		13.8		0.2		13.4		0.2
Total assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Derivative liabilities
Forward power contracts		10.6		-		10.6		-
Total Derivative liabilities		10.6		-		10.6		-
Long-term debt		859.6		-		841.1		18.5
Total liabilities	$	870.2	$	-	$	851.7	$	18.5

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		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended			3 Months Ended		9 Months Ended				9 Months Ended						3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 Forward Contract Power [Member]	Sep. 30, 2013 Forward Contract Power [Member]	Sep. 30, 2014 Forward Contract Power [Member]	Dec. 31, 2012 Forward Contract Power [Member]	Sep. 30, 2013 Interest Rate Contract [Member]	Sep. 30, 2014 Interest Rate Contract [Member]	Sep. 30, 2013 Interest Rate Contract [Member]	Jun. 30, 2014 Interest Rate Contract [Member]	Sep. 30, 2014 DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2013 DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2014 DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2014 DP&L [Member] Forward Contract Power [Member]	Mar. 31, 2013 DP&L [Member] Forward Contract Power [Member]	Dec. 31, 2012 DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2014 DP&L [Member] Interest Rate Contract [Member]	Mar. 31, 2014 DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2013 DP&L [Member] Interest Rate Contract [Member]	Mar. 31, 2013 DP&L [Member] Interest Rate Contract [Member]	Dec. 31, 2012 DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2012 DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2014 Interest Expense [Member] Interest Rate Contract [Member]	Sep. 30, 2014 Interest Expense [Member] Interest Rate Contract [Member]	Sep. 30, 2014 Interest Expense [Member] DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2013 Interest Expense [Member] DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2014 Interest Expense [Member] DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2012 Interest Expense [Member] DP&L [Member] Interest Rate Contract [Member]	Sep. 30, 2014 Revenue [Member] Forward Contract Power [Member]	Sep. 30, 2013 Revenue [Member] Forward Contract Power [Member]	Sep. 30, 2014 Revenue [Member] Forward Contract Power [Member]	Sep. 30, 2013 Revenue [Member] Forward Contract Power [Member]	Sep. 30, 2014 Revenue [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2013 Revenue [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2014 Revenue [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2013 Revenue [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2014 Purchased Power [Member] Forward Contract Power [Member]	Sep. 30, 2013 Purchased Power [Member] Forward Contract Power [Member]	Sep. 30, 2014 Purchased Power [Member] Forward Contract Power [Member]	Sep. 30, 2013 Purchased Power [Member] Forward Contract Power [Member]	Sep. 30, 2014 Purchased Power [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2013 Purchased Power [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2014 Purchased Power [Member] DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2013 Purchased Power [Member] DP&L [Member] Forward Contract Power [Member]
Beginning accumulated derivative gain / (loss) in AOCI					$ (12.4)	$ (1.1)	$ 1.4	$ (3.0)	$ 12.8	$ 19.2	$ 0.5	$ 18.8			$ 1.0	$ (14.0)	$ (1.9)	$ (4.7)	$ 5.2	$ 4.6	$ 5.5	$ 6.1	$ 7.3	$ 5.5
Net gains / (losses) associated with current period hedging transactions					1.2	(0.2)	(23.8)		6.4		18.7		1.4	(0.3)
Net income (loss)	98.4	33.2	(116.8)	76.0
Ending accumulated derivative gain / (loss) in AOCI					(7.6)		(7.6)	(3.0)	19.2	18.6	19.2	18.8	(9.2)	(0.6)	(9.2)	(14.0)	(1.9)	(4.7)	4.4	4.6	5.5	6.1	7.3	5.5
Net gains / (losses) associated with the ineffective portion of the hedging transaction															(26.3)
Portion expected to be reclassified to earnings in the next twelve months					(7.3)		(7.3)			(0.6)			(7.2)		(7.2)				(1.1)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)							27 months			0 months					27 months				0 months
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net																									$ (0.2)	$ (0.6)	$ (0.2)	$ (0.6)	$ (0.8)	$ (1.8)	$ 3.4	$ 0.3	$ 15.4	$ 1.3	$ 3.2	$ 0.3	$ 16.6	$ 1.4	$ 0.2	$ 1.0	$ (0.6)	$ 1.7	$ 0.2	$ 1.3	$ (0.5)	$ 2.7

XML

Debt Obligations (Long-term Debt) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Total long-term debt at subsidary	$ 874.6	$ 874.6
Unamortized debt discount	(0.5)	(0.7)
Total long-term debt	2,154.3	2,284.2
DP&L [Member]
Unamortized debt discount	(0.5)	(0.7)
Total long-term debt	877.0	876.9
First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]
Debt instrument maturity year	May 01, 2018
Debt instrument interest percentage minimum	2.41%	2.42%
Debt instrument interest percentage maximum	2.42%	2.45%
First Mortgage Bonds Maturing in September 2016
Long-term debt, gross	445.0	445.0
Debt instrument maturity year	Sep. 01, 2016
Debt instrument interest percentage	1.875%
First Mortgage Bonds Maturing in September 2016 | DP&L [Member]
Long-term debt, gross	445.0	445.0
Debt instrument maturity year	Sep. 01, 2016
Debt instrument interest percentage	1.875%
Pollution Control Series Maturing in January 2028 - 4.70% [Member]
Long-term debt, gross	36.0	36.0
Debt instrument maturity year	Jan. 01, 2028
Debt instrument interest percentage	4.70%
Pollution Control Series Maturing in January 2028 - 4.70% [Member] | DP&L [Member]
Long-term debt, gross	35.3	35.3
Debt instrument maturity year	Jan. 01, 2028
Debt instrument interest percentage	4.70%
Pollution Control Series Maturing in January 2034 - 4.80% [Member]
Long-term debt, gross	179.6	179.6
Debt instrument maturity year	Jan. 01, 2034
Debt instrument interest percentage	4.80%
Pollution Control Series Maturing in January 2034 - 4.80% [Member] | DP&L [Member]
Long-term debt, gross	179.1	179.1
Debt instrument maturity year	Jan. 01, 2034
Debt instrument interest percentage	4.80%
Pollution Control Series Maturing in September 2036 - 4.80% [Member]
Long-term debt, gross	96.4	96.4
Debt instrument maturity year	Sep. 01, 2036
Debt instrument interest percentage	4.80%
Pollution Control Series Maturing in September 2036 - 4.80% [Member] | DP&L [Member]
Long-term debt, gross	100.0	100.0
Debt instrument maturity year	Sep. 01, 2036
Debt instrument interest percentage	4.80%
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]
Long-term debt, gross	100.0	100.0
Debt instrument maturity year	Nov. 01, 2040
Debt instrument interest percentage minimum	0.04%	0.05%
Debt instrument interest percentage maximum	0.15%	0.24%
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] | DP&L [Member]
Long-term debt, gross	100.0	100.0
Debt instrument maturity year	Nov. 01, 2040
Debt instrument interest percentage minimum	0.04%	0.05%
Debt instrument interest percentage maximum	0.15%	0.24%
U.S. Government note maturing in February 2061 - 4.20% [Member]
Long-term debt, gross	(18.1)	(18.3)
Debt instrument maturity year	Feb. 01, 2061
Debt instrument interest percentage	4.20%
Debt instrument interest percentage minimum	4.20%
U.S. Government note maturing in February 2061 - 4.20% [Member] | DP&L [Member]
Long-term debt, gross	18.1	18.2
Debt instrument maturity year	Feb. 01, 2061
Debt instrument interest percentage	4.20%
Debt instrument interest percentage minimum	4.20%
Bank Term Loan maturing in May 2018 [Member]
Long-term debt, gross	150.0	180.0
Debt instrument maturity year	May 01, 2018
Debt instrument interest percentage minimum	2.41%	2.42%
Debt instrument interest percentage maximum	2.42%	2.45%
Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]
Long-term debt, gross	19.7	19.6
Debt instrument maturity year	Sep. 01, 2031
Debt instrument interest percentage	8.125%
Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]
Long-term debt, gross	330.0	430.0
Debt instrument maturity year	Oct. 01, 2016
Debt instrument interest percentage	6.50%
Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]
Long-term debt, gross	$ 780.0	$ 780.0
Debt instrument maturity year	Oct. 01, 2021
Debt instrument interest percentage	7.25%

XML

Business Segments (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

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 September 30, 2014
Revenues from external customers	$	329.3	$	141.3	$	8.6	$	-	$	479.2
Intersegment revenues		125.6		-		3.0		(128.6)		-
Total revenues		454.9		141.3		11.6		(128.6)		479.2
Fuel		84.5		-		0.6		-		85.1
Purchased power		152.4		128.7		0.4		(127.8)		153.7
Amortization of intangibles		-		-		0.3		-		0.3
Gross margin	$	218.0	$	12.6	$	10.3	$	(0.8)	$	240.1
Depreciation and amortization	$	36.4	$	0.3	$	(2.2)	$	-	$	34.5
Interest expense		9.4		0.1		23.8		(0.2)		33.1
Income tax expense (benefit)		13.1		1.5		(55.6)		-		(41.0)
Net income / (loss)		53.2		3.0		42.2		-		98.4
Cash capital expenditures	$	25.6	$	0.5	$	0.3	$	-	$	26.4

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended September 30, 2013
Revenues from external customers	$	289.3	$	139.7	$	12.2	$	-	$	441.2
Intersegment revenues		123.8		-		1.0		(124.8)		-
Total revenues		413.1		139.7		13.2		(124.8)		441.2
Fuel		96.7		-		2.9		0.1		99.7
Purchased power		110.4		125.6		0.9		(123.8)		113.1
Amortization of intangibles		-		-		1.8		-		1.8
Gross margin	$	206.0	$	14.1	$	7.6	$	(1.1)	$	226.6
Depreciation and amortization	$	35.8	$	0.1	$	(2.0)	$	-	$	33.9
Interest expense		10.4		0.1		20.6		(0.1)		31.0
Income tax expense (benefit)		13.2		1.4		(3.3)		-		11.3
Net income / (loss)		40.9		2.5		(10.2)		-		33.2
Cash capital expenditures	$	28.3	$	-	$	1.0	$	-	$	29.3

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the nine months ended September 30, 2014
Revenues from external customers	$	875.9	$	414.9	$	38.8	$	-	$	1,329.6
Intersegment revenues		376.6		-		4.1		(380.7)		-
Total revenues		1,252.5		414.9		42.9		(380.7)		1,329.6
Fuel		227.4		-		8.5		-		235.9
Purchased power		457.3		380.0		7.1		(378.2)		466.2
Amortization of intangibles		-		-		0.9		-		0.9
Gross margin	$	567.8	$	34.9	$	26.4	$	(2.5)	$	626.6
Depreciation and amortization	$	108.2	$	0.6	$	(5.1)	$	-	$	103.7
Goodwill impairment		-		-		135.8		-		135.8
Fixed-asset impairment		-		-		11.5		-		11.5
Interest expense		25.5		0.3		70.5		(0.5)		95.8
Income tax expense (benefit)		23.1		2.1		4.5		-		29.7
Net income / (loss)		76.5		4.2		(197.5)		-		(116.8)
Cash capital expenditures	$	78.6	$	0.5	$	2.5	$	-	$	81.6
At September 30, 2014
Total assets	$	3,245.3	$	100.3	$	1,536.9	$	(1,339.9)	$	3,542.6

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the nine months ended September 30, 2013
Revenues from external customers	$	805.5	$	381.9	$	23.3	$	-	$	1,210.7
Intersegment revenues		336.0		-		3.0		(339.0)		-
Total revenues		1,141.5		381.9		26.3		(339.0)		1,210.7
Fuel		269.6		-		4.2		0.2		274.0
Purchased power		276.7		340.8		1.5		(336.4)		282.6
Amortization of intangibles		-		-		5.3		-		5.3
Gross margin	$	595.2	$	41.1	$	15.3	$	(2.8)	$	648.8
Depreciation and amortization	$	104.5	$	0.4	$	(5.9)	$	-	$	99.0
Interest expense		29.7		0.4		61.5		(0.5)		91.1
Income tax expense (benefit)		29.2		4.3		(12.7)		-		20.8
Net income / (loss)		101.4		7.7		(33.1)		-		76.0
Cash capital expenditures	$	95.1	$	-	$	1.4	$	-	$	96.5
At December 31, 2013
Total assets	$	3,313.1	$	105.0	$	1,675.8	$	(1,372.4)	$	3,721.5

XML

Summary of Significant Accounting Policies (Narrative) (Details)	9 Months Ended
	Sep. 30, 2014 sqmi employee
Service Area Square Miles	6,000
Approximate number of retail customers	515,000
Electric generation through competitive bid	10.00%
Approximate number of DPLER customers	274,000
Entity number of employees	1,197
Number of coal fired power plants	7
Employees under a collective bargaining agreement which expires in October-2011	61.00%
DP&L [Member]
Service Area Square Miles	6,000
Approximate number of retail customers	515,000
Entity number of employees	1,142
Employees under a collective bargaining agreement which expires in October-2011	63.00%
Year 2014 [Member] | DP&L [Member]
Electric generation through competitive bid	10.00%
Year 2015 [Member]
Electric generation through competitive bid	60.00%
Year 2015 [Member] | DP&L [Member]
Electric generation through competitive bid	60.00%
Year 2016 [Member]
Electric generation through competitive bid	100.00%
Year 2016 [Member] | DP&L [Member]
Electric generation through competitive bid	100.00%

XML

Supplemental Financial Information

9 Months Ended

Sep. 30, 2014

Supplemental Financial Information

2. Supplemental Financial Information 

Accounts receivable and Inventories are as follows at September 30, 2014 and December 31, 2013:

	September 30,		December 31,
$ in millions	2014		2013
Accounts receivable, net:
Unbilled revenue	$	65.7	$	77.8
Customer receivables		112.9		102.7
Amounts due from partners in jointly owned plants		10.4		15.8
Other		3.0		8.2
Provision for uncollectible accounts		(1.3)		(1.2)
Total accounts receivable, net	$	190.7	$	203.3
Inventories, at average cost:
Fuel and limestone	$	48.5	$	42.7
Plant materials and supplies		36.2		38.2
Other		1.7		1.8
Total inventories, at average cost	$	86.4	$	82.7

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months endedSeptember 30, 2014 and 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended				Nine months ended
		September 30,				September 30,
$ in millions		2014		2013		2014		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income	$	0.3	$	0.6	$	0.6	$	2.1
	Tax expense		(0.1)		(0.2)		(0.2)		(0.7)
	Net of income taxes		0.2		0.4		0.4		1.4
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.3)		-		(1.0)		-
	Revenue		4.9		0.5		23.4		2.2
	Purchased power		0.3		1.6		(0.8)		2.9
	Total before income taxes		4.9		2.1		21.6		5.1
	Tax expense		(1.5)		(0.8)		(7.4)		(2.1)
	Net of income taxes		3.4		1.3		14.2		3.0
Amortization of defined benefit pension items (Note 7):
	Tax benefit		-		-		-		0.3
	Net of income taxes		-		-		-		0.3
Total reclassifications for the period, net of income taxes		$	3.6	$	1.7	$	14.6	$	4.7

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2014 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, 2014	$	0.6	$	20.6	$	3.4	$	24.6
Other comprehensive loss before reclassifications		(0.6)		(23.8)		-		(24.4)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.4		14.2		-		14.6
Net current period other comprehensive loss		(0.2)		(9.6)		-		(9.8)
Balance September 30, 2014	$	0.4	$	11.0	$	3.4	$	14.8

DP&L [Member]

Supplemental Financial Information

2.  Supplemental Financial Information 

Accounts receivable and Inventories are as follows at September 30, 2014 and December 31, 2013:

	September 30,		December 31,
$ in millions	2014		2013
Accounts receivable, net:
Unbilled revenue	$	36.0	$	47.2
Customer receivables		70.3		58.2
Amounts due from partners in jointly owned plants		10.4		15.8
Other		27.0		27.2
Provision for uncollectible accounts		(0.9)		(0.9)
Total accounts receivable, net	$	142.8	$	147.5
Inventories, at average cost:
Fuel and limestone	$	48.5	$	42.9
Plant materials and supplies		35.0		37.0
Other		1.7		1.8
Total inventories, at average cost	$	85.2	$	81.7

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months endedSeptember 30, 2014 and 2013 are as follows:

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended				Nine months ended
		September 30,				September 30,
$ in millions		2014		2013		2014		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income	$	0.3	$	0.6	$	0.6	$	2.1
	Tax expense		(0.1)		(0.2)		(0.2)		(0.7)
	Net of income taxes		0.2		0.4		0.4		1.4
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.2)		(0.6)		(0.8)		(1.8)
	Revenue		4.9		0.4		23.4		2.1
	Purchased power		0.4		2.0		(0.6)		4.2
	Total before income taxes		5.1		1.8		22.0		4.5
	Tax expense		(1.9)		(0.8)		(6.7)		(2.2)
	Net of income taxes		3.2		1.0		15.3		2.3
Amortization of defined benefit pension items (Note 7):
	Reclassification to Other income / (deductions)		1.0		1.4		3.1		4.2
	Tax benefit		(0.3)		(0.5)		(1.0)		(1.5)
	Net of income taxes		0.7		0.9		2.1		2.7
Total reclassifications for the period, net of income taxes		$	4.1	$	2.3	$	17.8	$	6.4

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months endedSeptember 30, 2014 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, 2014	$	0.8	$	6.2	$	(33.7)	$	(26.7)
Other comprehensive loss before reclassifications		(0.6)		(26.3)		-		(26.9)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.4		15.3		2.1		17.8
Net current period other comprehensive loss		(0.2)		(11.0)		2.1		(9.1)
Balance September 30, 2014	$	0.6	$	(4.8)	$	(31.6)	$	(35.8)

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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		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
State/Local excise taxes	$ 12.5	$ 13.0	$ 38.5	$ 38.0
DP&L [Member]
State/Local excise taxes	$ 12.5	$ 13.0	$ 38.5	$ 38.0

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Regulatory Matters (Schedule of Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Regulatory Matters [Abstract]
Total current regulatory assets	$ 30.0	$ 20.8
Total non-current regulatory assets	147.8	159.7
Total current regulatory liabilities	10.0
Total non-current regulatory liabilities	$ 123.7	$ 121.1

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on a Nonrecurring Basis) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Mar. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Carrying Value		$ 2,501.4	$ 2,534.2
Fixed asset impairment		11.5
Goodwill		317.0	452.8
Goodwill Impairment	135.8	135.8
Parent Company [Member]
Fixed asset impairment		11.5
Goodwill Impairment		135.8
DPLER [Member]
Goodwill Impairment		135.8
DPLER [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Goodwill Impairment		135.8
East Bend Station [Member]
Fixed asset impairment		11.5
Fair Value		2.7
East Bend Station [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fixed asset impairment		14.2
East Bend Station [Member] | Level 3 [Member]
Fixed asset impairment		$ 2.7

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Consolidated Statements of Results of Operations (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues	$ 479.2	$ 441.2	$ 1,329.6	$ 1,210.7
Cost of revenues:
Fuel	85.1	99.7	235.9	274.0
Purchased power	153.7	113.1	466.2	282.6
Amortization of intangibles	0.3	1.8	0.9	5.3
Total cost of revenues	239.1	214.6	703.0	561.9
Gross margin	240.1	226.6	626.6	648.8
Operating expenses:
Operation and maintenance	94.0	97.3	294.7	297.4
Depreciation and amortization	34.5	33.9	103.7	99.0
Taxes, Miscellaneous	21.2	19.4	70.3	60.8
Goodwill Impairment			135.8
Fixed asset impairment			11.5
Total operating expenses	149.7	150.6	616.0	457.2
Operating income	90.4	76.0	10.6	191.6
Other income / (expense), net:
Investment income	0.2	(0.5)	0.6	1.2
Interest expense	(33.1)	(31.0)	(95.8)	(91.1)
Other deductions	(0.1)		(2.5)	(4.9)
Total other income / (expense), net	(33.0)	(31.5)	(97.7)	(94.8)
Earnings before income tax	57.4	44.5	(87.1)	96.8
Income tax expense	(41.0)	11.3	29.7	20.8
Net income	98.4	33.2	(116.8)	76.0
THE DAYTON POWER AND LIGHT COMPANY [Member]
Revenues	454.9	413.1	1,252.5	1,141.5
Cost of revenues:
Fuel	84.5	96.7	227.4	269.6
Purchased power	152.4	110.4	457.3	276.7
Total cost of revenues	236.9	207.1	684.7	546.3
Gross margin	218.0	206.0	567.8	595.2
Operating expenses:
Operation and maintenance	85.9	87.6	265.9	270.4
Depreciation and amortization	36.4	35.8	108.2	104.5
Taxes, Miscellaneous	20.2	18.2	67.1	57.4
Total operating expenses	142.5	141.6	441.2	432.3
Operating income	75.5	64.4	126.6	162.9
Other income / (expense), net:
Investment income	0.2	0.1	0.6	1.7
Interest expense	(9.4)	(10.4)	(25.5)	(29.7)
Other deductions			(2.1)	(4.3)
Total other income / (expense), net	(9.2)	(10.3)	(27.0)	(32.3)
Earnings before income tax	66.3	54.1	99.6	130.6
Income tax expense	13.1	13.2	23.1	29.2
Net income	53.2	40.9	76.5	101.4
Dividends on preferred stock	0.3	0.2	0.7	0.6
Earnings on common stock	$ 52.9	$ 40.7	$ 75.8	$ 100.8

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Debt Obligations (Current portion - Long-term Debt) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Obligation for capital lease		$ 0.1
Current portion - long-term debt	110.1	10.2
DP&L [Member]
Obligation for capital lease		0.1
Current portion - long-term debt	0.1	0.2
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member]
Debt instrument maturity year	Nov. 01, 2040
Debt instrument interest percentage minimum	0.04%	0.05%
Debt instrument interest percentage maximum	0.15%	0.24%
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% [Member] | DP&L [Member]
Debt instrument maturity year	Nov. 01, 2040
Debt instrument interest percentage minimum	0.04%	0.05%
Debt instrument interest percentage maximum	0.15%	0.24%
First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]
Current portion - long-term debt	10.0	10.0
Debt instrument maturity year	May 01, 2018
Debt instrument interest percentage minimum	2.41%	2.42%
Debt instrument interest percentage maximum	2.42%	2.45%
First Mortgage Bonds Maturing in October 2013 - 5.125% [Member] | DP&L [Member]
Current portion - long-term debt	0.1	0.1
U.S. Government note maturing in February 2061 - 4.20% [Member]
Debt instrument maturity year	Feb. 01, 2061
Debt instrument interest percentage	4.20%
Debt instrument interest percentage minimum	4.20%
U.S. Government note maturing in February 2061 - 4.20%, current	0.1	0.1
U.S. Government note maturing in February 2061 - 4.20% [Member] | DP&L [Member]
Debt instrument maturity year	Feb. 01, 2061
Debt instrument interest percentage	4.20%
Debt instrument interest percentage minimum	4.20%
Bank Term Loan maturing in May 2018 [Member]
Debt instrument maturity year	May 01, 2018
Debt instrument interest percentage minimum	2.41%	2.42%
Debt instrument interest percentage maximum	2.42%	2.45%
Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]
Current portion - long-term debt	$ 100.0
Debt instrument maturity year	Oct. 01, 2016
Debt instrument interest percentage	6.50%

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 104.1	$ 53.2
Restricted Cash	22.5	13.5
Accounts receivable, net (Note 2)	190.7	203.3
Inventories (Note 2)	86.4	82.7
Taxes applicable to subsequent years	18.5	70.6
Regulatory assets, current (Note 3)	30.0	20.8
Other prepayments and current assets	44.9	35.1
Total current assets	497.1	479.2
Property, plant and equipment:
Property, plant and equipment	2,724.1	2,677.0
Less: Accumulated depreciation and amortization	(288.5)	(206.7)
Property, plant and equipment, net of depreciation	2,435.6	2,470.3
Construction work in process	65.8	63.9
Total net property, plant and equipment	2,501.4	2,534.2
Other noncurrent assets:
Regulatory assets, non-current (Note 3)	147.8	159.7
Goodwill	317.0	452.8
Intangible assets, Net of amortization (Note 6)	38.6	42.8
Other deferred assets	40.7	52.8
Total other noncurrent assets	544.1	708.1
Total Assets	3,542.6	3,721.5
Current liabilities:
Current portion - long-term debt (Note 5)	110.1	10.2
Accounts payable	77.4	78.2
Accrued taxes	131.9	89.4
Accrued interest	43.2	28.5
Customer security deposits	14.4	13.9
Regulatory liabilities, current	10.0
Insurance and claims costs	7.0	6.7
Other current liabilities	66.3	64.2
Total current liabilities	460.3	291.1
Noncurrent liabilities:
Long-term debt (Note 5)	2,154.3	2,284.2
Deferred taxes (Note 6)	553.4	564.3
Taxes Payable	3.0	79.1
Regulatory liabilities, non-current (Note 3)	123.7	121.1
Pension, retiree and other benefits (Note 9)	42.7	51.6
Unamortized investment tax credit	2.4	2.8
Other deferred credits	71.0	69.4
Total noncurrent liabilities	2,950.5	3,172.5
Redeemable preferred stock	18.4	18.4
Common shareholders' equity:
Other paid-in capital	2,237.5	2,237.0
Accumulated other comprehensive loss	14.8	24.6
Retained earnings/ (deficit)	(2,138.9)	(2,022.1)
Total common shareholders' equity	113.4	239.5
Total Liabilities and Shareholders' Equity	3,542.6	3,721.5
THE DAYTON POWER AND LIGHT COMPANY [Member]
Current assets:
Cash and cash equivalents	31.0	22.9
Restricted Cash	22.5	13.0
Accounts receivable, net (Note 2)	142.8	147.5
Inventories (Note 2)	85.2	81.7
Taxes applicable to subsequent years	18.0	68.5
Regulatory assets, current (Note 3)	30.0	20.8
Other prepayments and current assets	43.1	32.5
Total current assets	372.6	386.9
Property, plant and equipment:
Property, plant and equipment	5,161.2	5,105.3
Less: Accumulated depreciation and amortization	(2,539.6)	(2,448.1)
Property, plant and equipment, net of depreciation	2,621.6	2,657.2
Construction work in process	65.1	60.9
Total net property, plant and equipment	2,686.7	2,718.1
Other noncurrent assets:
Regulatory assets, non-current (Note 3)	147.8	159.7
Intangible assets, Net of amortization (Note 6)	7.7	8.3
Other deferred assets	30.5	40.1
Total other noncurrent assets	186.0	208.1
Total Assets	3,245.3	3,313.1
Current liabilities:
Current portion - long-term debt (Note 5)	0.1	0.2
Accounts payable	73.9	73.9
Accrued taxes	108.2	81.0
Accrued interest	4.1	9.6
Customer security deposits	34.5	33.1
Regulatory liabilities, current	10.0
Other current liabilities	62.3	59.7
Total current liabilities	293.1	257.5
Noncurrent liabilities:
Long-term debt (Note 5)	877.0	876.9
Deferred taxes (Note 6)	629.6	632.3
Taxes Payable		76.5
Regulatory liabilities, non-current (Note 3)	123.7	121.1
Pension, retiree and other benefits (Note 9)	42.7	51.6
Unamortized investment tax credit	23.0	24.9
Other deferred credits	52.6	45.4
Total noncurrent liabilities	1,748.6	1,828.7
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	803.5	803.5
Accumulated other comprehensive loss	(35.8)	(26.7)
Retained earnings/ (deficit)	412.6	426.8
Total common shareholders' equity	1,180.7	1,204.0
Total Liabilities and Shareholders' Equity	$ 3,245.3	$ 3,313.1

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Derivative Instruments and Hedging Activities (Fair Value and Balance Sheet Location (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014 DP&L [Member]	Sep. 30, 2014 Total Assets [Member]	Dec. 31, 2013 Total Assets [Member]	Sep. 30, 2014 Total Assets [Member] DP&L [Member]	Dec. 31, 2013 Total Assets [Member] DP&L [Member]	Sep. 30, 2014 Total Liabilities [Member]	Dec. 31, 2013 Total Liabilities [Member]	Sep. 30, 2014 Total Liabilities [Member] DP&L [Member]	Dec. 31, 2013 Total Liabilities [Member] DP&L [Member]	Dec. 31, 2013 Commodity Contract - FTR [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member]	Dec. 31, 2013 Commodity Contract - FTR [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member] DP&L [Member]	Sep. 30, 2014 Commodity Contract - FTR [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member]	Mar. 31, 2014 Commodity Contract - FTR [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member] DP&L [Member]	Dec. 31, 2013 Commodity Contract - Heating Oil [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member]	Sep. 30, 2014 Commodity Contract - Heating Oil [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member]	Sep. 30, 2014 Commodity Contract - Heating Oil [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member] DP&L [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member] DP&L [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member] DP&L [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member] DP&L [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member] DP&L [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Deferred Credit [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Credit [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Credit [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Credit [Member] DP&L [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Credit [Member] DP&L [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member]	Sep. 30, 2014 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member] DP&L [Member]	Dec. 31, 2013 Not Designated as Hedging Instrument [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member] DP&L [Member]	Dec. 31, 2013 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]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member]	Dec. 31, 2013 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member] DP&L [Member]	Dec. 31, 2013 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Prepayments and Current Assets [Member] DP&L [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member]	Dec. 31, 2013 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member] DP&L [Member]	Dec. 31, 2013 Cash Flow Hedging [Member] Forward Contract Power [Member] Short-term Derivative Positions [Member] Other Current Liabilities [Member] DP&L [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Credit [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Credit [Member] DP&L [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member]	Dec. 31, 2013 Cash Flow Hedging [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member]	Sep. 30, 2014 Cash Flow Hedging [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member] DP&L [Member]	Dec. 31, 2013 Cash Flow Hedging [Member] Forward Contract Power [Member] Long-term Derivative Positions [Member] Other Deferred Asset [Member] DP&L [Member]
Derivative Asset, Fair Value			$ 11.2	$ 13.8	$ 11.7	$ 13.8					$ 0.2	$ 0.2			$ 0.2			$ 6.3	$ 4.9	$ 6.5	$ 4.9									$ 3.3	$ 5.0	$ 3.6	$ 5.0	$ 0.2	$ 0.9	$ 0.5	$ 0.9	$ 0.5							$ 0.7	$ 3.0	$ 0.7	$ 3.0
Derivative, Fair Value, Net			1.7	5.9	2.1	5.9	4.4	0.3	4.4	0.3	0.2	0.2	1.0	1.0				0.9	0.7	1.1	0.7	2.0	2.0	0.1	0.1	0.1		0.1		0.8	4.7	1.0	4.7			0.3		0.3	1.3	0.2	1.3	0.2
Derivative, Collateral, net			(0.1)	(3.2)	(0.1)	(3.2)	(14.1)	(5.6)	(14.1)	(5.6)					(0.2)	(0.1)	(0.1)					(2.8)	(2.8)	(2.3)	(2.3)	(0.7)	(1.0)	(0.7)	(1.0)					(0.2)					(9.8)	(2.3)	(9.8)	(2.3)	(0.7)	(0.7)	(0.1)	(3.0)	(0.1)	(3.0)
Derivative, Fair Value, Offset, Net			(9.4)	(4.7)	(9.5)	(4.7)	(9.5)	(4.7)	(9.5)	(4.7)								(5.4)	(4.2)	(5.4)	(4.2)	(5.4)	(5.4)	(4.2)	(4.2)	(2.6)	(0.3)	(2.6)	(0.3)	(2.5)	(0.3)	(2.6)	(0.3)		(0.9)	(0.2)	(0.9)	(0.2)	(0.9)	(0.2)	(0.9)	(0.2)	(0.6)	(0.6)	(0.6)		(0.6)
Derivative Liability, Fair Value	$ 28.0	$ 28.0					$ 28.0	$ 10.6	$ 28.0	$ 10.6			$ 1.0	$ 1.0		$ 0.1	$ 0.1					$ 10.2	$ 10.2	$ 6.6	$ 6.6	$ 3.4	$ 1.3	$ 3.4	$ 1.3										$ 12.0	$ 2.7	$ 12.0	$ 2.7	$ 1.3	$ 1.3

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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		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Excise Taxes Collected	$ 12.5	$ 13.0	$ 38.5	$ 38.0
DP&L [Member]
Excise Taxes Collected	$ 12.5	$ 13.0	$ 38.5	$ 38.0

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Common Shareholders' Equity (Details) (DP&L [Member], USD $)	9 Months Ended
	Sep. 30, 2014
DP&L [Member]
Common stock, shares authorized	250,000,000
Common stock, shares outstanding	41,172,173
Par Value common shares	$ 0.01
PUCO Meger Equity Ratio Approval	50.00%

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Member]

Schedule of Related Party Transactions [Table Text Block]

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Transactions with the Service Company
Charges for services provided	$	5.5	$	-	$	27.8	$	-
Charges to the Service Company		0.2		-		0.2		-

Related Party Balances [Member]

Schedule of Related Party Transactions [Table Text Block]

Transactions with the Service Company	At September 30, 2014		At December 31, 2013
Net prepaid / (payable) to the Service Company	$	9.4	$	-

DP&L [Member] | Related Party Transactions [Member]

Schedule of Related Party Transactions [Table Text Block]

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
DP&L Revenues:
Sales to DPLER (including MC Squared) (a)	$	125.6	$	123.8	$	376.6	$	336.0
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.7)	$	(2.1)	$	(2.2)
Expense recoveries for services provided to DPLER (c)	$	0.5	$	1.3	$	1.6	$	3.8
Transactions with the Service Company
Charges for services provided	$	9.0	$	-	$	28.1	$	-

DP&L [Member] | Related Party Balances [Member]

Schedule of Related Party Transactions [Table Text Block]

DP&L Customer security deposits:	At September 30, 2014		At December 31, 2013
Deposits received from DPLER (d)	$	20.1	$	19.2
Balances with the Service Company
Net prepaid / (payable) to the Service Company	$	9.4	$	-

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Supplemental Financial Information (Supplemental Financial Information) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Unbilled revenue	$ 65.7	$ 77.8
Customer receivables	112.9	102.7
Amounts due from partners in jointly owned stations	10.4	15.8
Other	3.0	8.2
Provision for uncollectible accounts	(1.3)	(1.2)
Total accounts receivable, net	190.7	203.3
Fuel and Limestone	48.5	42.7
Plant materials and supplies	36.2	38.2
Other	1.7	1.8
Total inventories, at average cost	86.4	82.7
DP&L [Member]
Unbilled revenue	36.0	47.2
Customer receivables	70.3	58.2
Amounts due from partners in jointly owned stations	10.4	15.8
Other	27.0	27.2
Provision for uncollectible accounts	(0.9)	(0.9)
Total accounts receivable, net	142.8	147.5
Fuel and Limestone	48.5	42.9
Plant materials and supplies	35.0	37.0
Other	1.7	1.8
Total inventories, at average cost	$ 85.2	$ 81.7

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Ownership of Coal-fired Facilities (Tables)

9 Months Ended

Sep. 30, 2014

Ownership Interests

	DP&L Share			DPL Carrying value
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	$	2	$	1	$	-	No
Conesville Unit 4	16.5	129		24		1		-	Yes
East Bend Station	31.0	186		-		-		-	Yes
Killen Station	67.0	402		309		17		2	Yes
Miami Fort Units 7 and 8	36.0	368		213		21		1	Yes
Stuart Station	35.0	808		213		15		12	Yes
Zimmer Station	28.1	365		181		33		4	Yes
Transmission (at varying percentages)		n/a		42		5		-
Total		2,465	$	984	$	93	$	19

DP&L [Member]

Ownership Interests

	DP&L Share			DP&L Carrying value
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	$	74	$	-	No
Conesville Unit 4	16.5	129		22		3		-	Yes
East Bend Station	31.0	186		2		1		-	Yes
Killen Station	67.0	402		624		311		2	Yes
Miami Fort Units 7 and 8	36.0	368		361		159		1	Yes
Stuart Station	35.0	808		751		319		12	Yes
Zimmer Station	28.1	365		1,100		670		4	Yes
Transmission (at varying percentages)		n/a		98		62		-
Total		2,465	$	3,034	$	1,599	$	19

XML

Overview and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2014

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.  The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES.  Following the Merger, DPL became an indirectly wholly owned subsidiary of AES.

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated.  DP&L has the exclusive right to provide such distribution and transmission services to its more than 515,000 customers located in West Central Ohio.  Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense.  DP&L's sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity.  DP&L sells any excess energy and capacity into the wholesale market.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.  DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

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.  DPLER has approximately 274,000 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 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 our subsidiaries and us.  DPLowns all of the common stock of its subsidiaries. 

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 1,197 people as of September 30, 2014, of which 1,142 were employed by DP&L.  Approximately 61% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.The current collective bargaining agreement was ratified by the membership on October 30, 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 has undivided ownership interests in seven coal-fired and peaking generating facilities as well as numerous transmission facilities,all of which 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 Statements of Results 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, 2013. 

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 September 30, 2014; our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013.  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 EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014. 

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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles. 

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value.

Goodwill Impairment

In connection with the Merger, DPL re-measured 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.  DPL’s annual testing date for goodwill is October 1 of each year.  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 certain events, 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 

DPLER sells receivables from its customers in Duke Energy’s territory to Duke Energy.  Receivables sold to Duke Energy during the three months ended September 30, 2014 and 2013 were $10.6 million and $6.1 million, respectively.  Receivables sold to Duke Energy during the nine months ended September 30, 2014 and 2013 were $30.4 million and $15.6 million, respectively.  Similarly, MC Squared sells receivables from its customers in ComEd territory to ComEd.  Receivables sold to ComEd during the three months ended September 30, 2014 and 2013 were $27.1 million and $22.6 million, respectively.  Receivables sold to ComEd during the ninemonths ended September 30, 2014 and 2013 were $68.3 million and $57.8 million, respectively. There is no recourse or any other continuing involvement associated with the sold receivables.These sales are at face value for cash at the amounts billed for DPLER or MC Squared customers’ use of energy. 

Regulatory Accounting

As a regulated utility, DP&L applies the provisions of FASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory assets can also represent performance incentives permitted by the regulator, such as with our Energy Efficiency Shared Savings.  Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices.  Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DPL expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable.  In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment.  To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.  Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs.  It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval.  Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.  See Note 3 for more information about Regulatory Assets.

Property, Plant & 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 except for adjustments of generating plants to fair market value recorded in connection with the Merger, subsequent impairments and the adjustment of certain intangible assets to fair market value in connection with the 2011 acquisition of MC Squared by DPLER. 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. 

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 and customer contracts.  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 and nine months ended September 30, 2014 and 2013, gains from the sale of emission allowances were immaterial. 

Customer relationships recognized as part of the purchase accounting associated with the Merger are amortized over ten to seventeen years and customer contracts were amortized over the average length of the contracts.  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 not included in revenue.  The amounts of such taxes collected for the three months ended September 30, 2014 and 2013 were $12.5 million and $13.0 million, respectively.  The amounts of such taxes collected for theninemonths ended September 30, 2014 and 2013 were $38.5 million and $38.0 million, respectively.

Related Party Transactions 

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L.  The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations.  This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Transactions with the Service Company
Charges for services provided	$	5.5	$	-	$	27.8	$	-
Charges to the Service Company		0.2		-		0.2		-

Transactions with the Service Company	At September 30, 2014		At December 31, 2013
Net prepaid / (payable) to the Service Company	$	9.4	$	-

DPL has issued debt to a wholly owned business trust, DPL Capital Trust II.

Recently Issued Accounting Standards

Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016.  ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.  There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.  This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application.  The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns.  Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.  We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” effective for annual and interim periods beginning after December 15, 2014.  ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results.  In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes.  For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes.  Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact 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.  Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated.  DP&L has the exclusive right to provide such distribution and transmission services to its more than 515,000 customers located in West Central Ohio.  Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense.  DP&L's sales reflect the general economic conditions, seasonal weather patterns,retail competition in our service territory  and the market price of electricity.  DP&L sells any excess energy and capacity into the wholesale market.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.  While the OCC filed an application for rehearing on this Commission Order, it was denied by final order issued on July 23, 2014.  DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.DP&L is a subsidiary of DPL. 

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 1,142 people as of September 30, 2014.  Approximately 63% of all employees are under a collective bargaining agreement which expires on October 31, 2017.  The current collective bargaining agreement was ratified by the membership on October 30, 2014.

Financial Statement Presentation

DP&L does not have any subsidiaries.  DP&L has undivided ownership interests in seven coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of 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 Statements of Results 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, 2013. 

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 September 30, 2014; our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013.  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 EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014. 

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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; intangibles and assets and liabilities related to employee benefits.

Regulatory Accounting

As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations,”which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory assets can also represent performance incentives permitted by the regulator, such as with our CCEM energy efficiency program.  Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices.  Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable.  In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment.  To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.  Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs.  It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval.  Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.  See Note 3 for more information about Regulatory Assets.

Property, Plant & 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 except for the impact of asset impairments recorded for certain generating plants.  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. 

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 and nine months ended September 30, 2014 and 2013, gains from the sale of emission allowances were immaterial.

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 not included in revenue.  The amounts of such taxes collected for the three months ended September 30, 2014 and 2013 were $12.5 million and $13.0 million, respectively.  The amounts of such taxes collected for the nine months ended September 30, 2014 and 2013 were $38.5 million and $38.0 million, respectively.

Related Party Transactions 

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DP&L.  The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations.  This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
DP&L Revenues:
Sales to DPLER (including MC Squared) (a)	$	125.6	$	123.8	$	376.6	$	336.0
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.7)	$	(2.1)	$	(2.2)
Expense recoveries for services provided to DPLER (c)	$	0.5	$	1.3	$	1.6	$	3.8
Transactions with the Service Company
Charges for services provided	$	9.0	$	-	$	28.1	$	-

DP&L Customer security deposits:	At September 30, 2014		At December 31, 2013
Deposits received from DPLER (d)	$	20.1	$	19.2
Balances with the Service Company
Net prepaid / (payable) to the Service Company	$	9.4	$	-

(a)DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers.  The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the nine months endedSeptember 30, 2014, compared to the nine months endedSeptember 30, 2013, is primarily due to an increase in customers.

(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

Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016.  ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.  There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.  This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application.  The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns.  Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.  We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” effective for annual and interim periods beginning after December 15, 2014.  ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results.  In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes.  For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes.  Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact on our overall results of operations, financial position or cash flows.

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Consolidated Statements of Comprehensive Income/(Loss) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Net income	$ 98.4	$ 33.2	$ (116.8)	$ 76.0
Available-for-sale securities activity:
Change in fair value of available-for-sale securities	(0.4)	0.2	(0.6)	(1.3)
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.2	0.4	0.4	1.4
Total change in fair value of available-for-sale securities	(0.2)	0.6	(0.2)	0.1
Derivative activity:
Change in derivative fair value	1.2	6.2	(23.8)	18.7
Reclassification of earnings, net of income tax (expense)/benefit of $0.6 and $(0.3), respectively	3.4	1.3	14.2	3.0
Total change in fair value of derivatives	4.6	7.5	(9.6)	21.7
Pension and postretirement activity:
Reclassification to earnings of Pension				0.3
Total change in unfunded pension obligation				0.3
Other comprehensive income / (loss)	4.4	8.1	(9.8)	22.1
Net comprehensive income / (loss)	102.8	41.3	(126.6)	98.1
THE DAYTON POWER AND LIGHT COMPANY [Member]
Net income	53.2	40.9	76.5	101.4
Available-for-sale securities activity:
Change in fair value of available-for-sale securities	(0.4)	(0.2)	(0.6)	(1.8)
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.2	0.4	0.4	1.4
Total change in fair value of available-for-sale securities	(0.2)	0.2	(0.2)	(0.4)
Derivative activity:
Change in derivative fair value	1.4	(0.3)	(26.3)
Reclassification of earnings, net of income tax (expense)/benefit of $0.6 and $(0.3), respectively	3.2	1.0	15.3	2.3
Total change in fair value of derivatives	4.6	0.7	(11.0)	2.3
Pension and postretirement activity:
Reclassification to earnings of Pension	0.7	0.9	2.1	2.7
Total change in unfunded pension obligation	0.7	0.9	2.1	2.7
Other comprehensive income / (loss)	5.1	1.8	(9.1)	4.6
Net comprehensive income / (loss)	$ 58.3	$ 42.7	$ 67.4	$ 106.0

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Business Segments

9 Months Ended

Sep. 30, 2014

Business Segments [Abstract]

Business Segments

11.  Business Segments 

DPL operates through two segments; Utility and Competitive Retail.  The Utility segment consists of the operations of DPL’s subsidiary, DP&L.  The Competitive Retail segment consists of DPL’s wholly owned subsidiaryDPLER, including DPLER’s wholly owned subsidiary, MC Squared.  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 sold to DP&L’s standard service offer customers is primarily generated at seven coal-fired power plants and DP&L distributes power to more than 515,000 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 PJM 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 274,000 customers located throughout Ohio and in Illinois.  This number includes 117,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier.  The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.  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 in the “Other” column in the following tables are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs including 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 September 30, 2014
Revenues from external customers	$	329.3	$	141.3	$	8.6	$	-	$	479.2
Intersegment revenues		125.6		-		3.0		(128.6)		-
Total revenues		454.9		141.3		11.6		(128.6)		479.2
Fuel		84.5		-		0.6		-		85.1
Purchased power		152.4		128.7		0.4		(127.8)		153.7
Amortization of intangibles		-		-		0.3		-		0.3
Gross margin	$	218.0	$	12.6	$	10.3	$	(0.8)	$	240.1
Depreciation and amortization	$	36.4	$	0.3	$	(2.2)	$	-	$	34.5
Interest expense		9.4		0.1		23.8		(0.2)		33.1
Income tax expense (benefit)		13.1		1.5		(55.6)		-		(41.0)
Net income / (loss)		53.2		3.0		42.2		-		98.4
Cash capital expenditures	$	25.6	$	0.5	$	0.3	$	-	$	26.4

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the three months ended September 30, 2013
Revenues from external customers	$	289.3	$	139.7	$	12.2	$	-	$	441.2
Intersegment revenues		123.8		-		1.0		(124.8)		-
Total revenues		413.1		139.7		13.2		(124.8)		441.2
Fuel		96.7		-		2.9		0.1		99.7
Purchased power		110.4		125.6		0.9		(123.8)		113.1
Amortization of intangibles		-		-		1.8		-		1.8
Gross margin	$	206.0	$	14.1	$	7.6	$	(1.1)	$	226.6
Depreciation and amortization	$	35.8	$	0.1	$	(2.0)	$	-	$	33.9
Interest expense		10.4		0.1		20.6		(0.1)		31.0
Income tax expense (benefit)		13.2		1.4		(3.3)		-		11.3
Net income / (loss)		40.9		2.5		(10.2)		-		33.2
Cash capital expenditures	$	28.3	$	-	$	1.0	$	-	$	29.3

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the nine months ended September 30, 2014
Revenues from external customers	$	875.9	$	414.9	$	38.8	$	-	$	1,329.6
Intersegment revenues		376.6		-		4.1		(380.7)		-
Total revenues		1,252.5		414.9		42.9		(380.7)		1,329.6
Fuel		227.4		-		8.5		-		235.9
Purchased power		457.3		380.0		7.1		(378.2)		466.2
Amortization of intangibles		-		-		0.9		-		0.9
Gross margin	$	567.8	$	34.9	$	26.4	$	(2.5)	$	626.6
Depreciation and amortization	$	108.2	$	0.6	$	(5.1)	$	-	$	103.7
Goodwill impairment		-		-		135.8		-		135.8
Fixed-asset impairment		-		-		11.5		-		11.5
Interest expense		25.5		0.3		70.5		(0.5)		95.8
Income tax expense (benefit)		23.1		2.1		4.5		-		29.7
Net income / (loss)		76.5		4.2		(197.5)		-		(116.8)
Cash capital expenditures	$	78.6	$	0.5	$	2.5	$	-	$	81.6
At September 30, 2014
Total assets	$	3,245.3	$	100.3	$	1,536.9	$	(1,339.9)	$	3,542.6

$ in millions	Utility		Competitive Retail		Other		Adjustments and Eliminations		DPL Consolidated
For the nine months ended September 30, 2013
Revenues from external customers	$	805.5	$	381.9	$	23.3	$	-	$	1,210.7
Intersegment revenues		336.0		-		3.0		(339.0)		-
Total revenues		1,141.5		381.9		26.3		(339.0)		1,210.7
Fuel		269.6		-		4.2		0.2		274.0
Purchased power		276.7		340.8		1.5		(336.4)		282.6
Amortization of intangibles		-		-		5.3		-		5.3
Gross margin	$	595.2	$	41.1	$	15.3	$	(2.8)	$	648.8
Depreciation and amortization	$	104.5	$	0.4	$	(5.9)	$	-	$	99.0
Interest expense		29.7		0.4		61.5		(0.5)		91.1
Income tax expense (benefit)		29.2		4.3		(12.7)		-		20.8
Net income / (loss)		101.4		7.7		(33.1)		-		76.0
Cash capital expenditures	$	95.1	$	-	$	1.4	$	-	$	96.5
At December 31, 2013
Total assets	$	3,313.1	$	105.0	$	1,675.8	$	(1,372.4)	$	3,721.5

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2014
Entity Registrant Name	DPL INC
Entity Central Index Key	0000787250
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
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	2014
Document Fiscal Period Focus	Q3
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

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Goodwill Impairment

9 Months Ended

Sep. 30, 2014

Goodwill and Intangible Asset Impairment [Abstract]

Goodwill Impairment

12. Goodwill Impairment

During the first quarter of 2014, we performed an interim impairment test on the$135.8 million in goodwill at our DPLER reporting unit.  The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.

In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business.

During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit.  There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter. 

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Consolidated Statements of Comprehensive Income/(Loss) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income tax (expense)/benefit on unrealized gains (losses) related to available-for-sale securities	$ 0.2	$ (0.1)	$ 0.2	$ 0.7
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	(0.1)	(0.2)	(0.7)	(0.2)
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(1.0)	(3.3)	12.4	(10.0)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(1.5)	(0.8)	(7.4)	(2.1)
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	0.1	0.2	0.9
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	(0.1)	(0.2)	(0.2)	(0.7)
Income tax (expense)/benefit on unrealized gains (losses) related to derivative activity	(0.7)	0.1	9.9
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(1.9)	(0.9)	(6.7)	(2.2)
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	$ (0.3)	$ (0.5)	$ (1.0)	$ (1.5)

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Income Taxes

9 Months Ended

Sep. 30, 2014

Income Taxes

6.  Income Taxes 

The following table details the effective tax rates for the three and nine months endedSeptember 30, 2014 and 2013. 

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	2014	2013
DPL	(71.5)%	25.4%	(34.2)%	21.5%

Income tax expense for the three and nine months endedSeptember 30, 2014 and 2013 was calculated using the estimated annual effective income tax rates for 2014 and 2013 of (42.3)% and 31.0%, respectively.  For the three and nine months endedSeptember 30, 2014 and September 30, 2013, management estimated 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 September 30, 2014, DPL’s current period effective rate is less than the estimated annual effective rate due to a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitations on the 2010 tax year.

For the nine months ended September 30, 2014, the decrease in DPL’s effective rate compared to the same period in 2013 primarily reflects decreased pre-tax earnings related to the non-deductible goodwill impairment during the first quarter of 2014, which is treated as a permanent item in the annual effective income tax rate, and a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitations on the 2010 tax year. 

For the nine months endedSeptember 30, 2013,  DPL’s current period effective rate was less than the estimated annual effective rate due primarily to a favorable resolution of the 2008 IRS examination in the first quarter of 2013 and a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years.

DP&L [Member]

Income Taxes

6.  Income Taxes 

The following table details the effective tax rates for the three and nine months endedSeptember 30, 2014 and 2013. 

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	2014	2013
DP&L	19.8%	24.4%	23.2%	22.5%

Income tax expense for the three and nine months endedSeptember 30, 2014 and 2013 was calculated using the estimated annual effective income tax rates for 2014 and 2013 of 30.5% and 29.5%, respectively.  For the three and nine months endedSeptember 30,2014 and 2013 management estimated 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 and nine months ended September 30, 2014, DP&L’s current period effective rate is less than the estimated annual effective rate due to a 2014 adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitations on the 2010 tax year.

For the nine months endedSeptember 30, 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 Internal Revenue Service examination in the first quarter of 2013 and the adjustment to the tax reserves due to uncertain tax positions related to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years.

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Debt Obligations

9 Months Ended

Sep. 30, 2014

Debt Obligations

5.  Debt Obligations 

Long-term debt

	September 30,		December 31,
$ in millions	2014		2013
First mortgage bonds due in September 2016 - 1.875%	$	445.0	$	445.0
Pollution control series due in January 2028 - 4.7%		36.0		36.0
Pollution control series due in January 2034 - 4.8%		179.6		179.6
Pollution control series due in September 2036 - 4.8%		96.4		96.4
Pollution control series due in November 2040 - rates from: 0.04% - 0.15% and 0.05% - 0.24% (a)		100.0		100.0
U.S. Government note due in February 2061 - 4.2%		18.1		18.3
Unamortized debt discount		(0.5)		(0.7)
Total long-term debt at subsidiary		874.6		874.6
Bank term loan due in May 2018 - rates from: 2.41% - 2.42% and 2.42% - 2.45% (a)		150.0		180.0
Senior unsecured bonds due in October 2016 - 6.5%		330.0		430.0
Senior unsecured bonds due in October 2021 - 7.25%		780.0		780.0
Note to DPL Capital Trust II due in September 2031 - 8.125% (b)		19.7		19.6
Total non-current portion of long-term debt	$	2,154.3	$	2,284.2

Current portion of long-term debt 

	September 30,		December 31,
$ in millions	2014		2013
Bank term loan due in May 2018 - rates from: 2.41% - 2.42% and 2.42% - 2.45% (a)	$	10.0	$	10.0
Senior unsecured bonds due in October 2016 - 6.5%		100.0		-
U.S. Government note due in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		-		0.1
Total current portion of long-term debt	$	110.1	$	10.2

(a)Range of interest rates for the nine months endedSeptember 30, 2014 and the twelve months ended December 31, 2013, respectively. 

(b)Note payable to related party. See Note 1: Related Party Transactions for additional information.

At September 30, 2014, maturities of long-term debt are as follows:

Due within the twelve months ending September 30,
($ in millions)
2015	$	110.1
2016		385.1
2017		470.1
2018		70.1
2019		0.1
Thereafter		1,232.7
Total maturities		2,268.2
Unamortized premiums and discounts		(3.8)
Total long-term debt	$	2,264.4

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

On May 10, 2013, DP&L closed a $300.0 million unsecured revolving credit agreement with a syndicated bank group. This $300.0 million facility has a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million.  At September 30, 2014, there were two letters of credit in the amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L.  Fees associated with this letter of credit facility were not material during the three and nine months ended September 30, 2014.

DP&L’s unsecured revolving credit agreement and DP&L’s amended standby letters of credit have two financial covenants, the first measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter.  The second financial covenant ratio compares 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.

On May 10, 2013, DPLentered into a $100.0 million unsecured revolving credit facility. This $100.0 million facility has a $100.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $50.0 million. This facility has a five year term expiring on May 10, 2018; however, if DPL has not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility shall be July 15, 2016.  At September 30, 2014, there was one letter of credit in the amount of $2.3 million outstanding, with the remaining $97.7 million available to DPL.Fees associated with this facility were not material during thethree months or nine months ended September 30, 2014 or 2013.

DPL’s unsecured revolving credit agreement and unsecured term loan have two financial covenants.  The first financial covenant, a 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, an 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. 

DPL’s unsecured revolving credit agreement and unsecured term loan restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities under certain credit rating scenarios.

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 of debt 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.  In December 2013, DPL executed an open market repurchase and successfully bought back $20 million of the first tranche and $20 million of the second tranche.  DPL paid a $1.9 million and a $0.5 million premium, respectively, to repurchase these bonds. Subsequent to repurchasing these bonds DPL immediately retired them. 

On September 6, 2014, DPL announced its intent to purchase a maximum of $280.0 million of aggregate principal of the Senior Unsecured bonds maturing October 2016 through a tender offer.  On October 6, DPL partially funded the tender by closing on a new bond issuance of $200.0 million of Senior Unsecured notes maturing October 2019, which were priced at 6.75% and increased the maximum amount of the tender to $300.0 million.  The remainder of the tender was funded with cash on hand and the use of the DPL revolving line of credit.  The tender offer expired on October 20, 2014.  The net balance paid with cash or current borrowings of $100.0 million has been reclassified as current as of September 30, 2014.

In October 2014, DPL repaid$5.0 million of the note due to Capital Trust II, which used the funds to repurchase securities in the open market at a slight premium.  Subsequent to repurchasing these securities Capital Trust II immediately retired them.

Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage.

DP&L [Member]

Debt Obligations

5.  Debt Obligations 

Long-term debt

	September 30,		December 31,
$ in millions	2014		2013
First mortgage bonds due in September 2016 - 1.875%		445.0		445.0
Pollution control series due in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series due in January 2034 - 4.8%		179.1		179.1
Pollution control series due in September 2036 - 4.8%		100.0		100.0
Pollution control series due in November 2040 - rates from: 0.04% - 0.15% and 0.05% - 0.24% (a)		100.0		100.0
U.S. Government note due in February 2061 - 4.2%		18.1		18.2
Unamortized debt discount		(0.5)		(0.7)
Total non-current portion of long-term debt	$	877.0	$	876.9

Current portion of long-term debt

	September 30,		December 31,
$ in millions	2014		2013
U.S. Government note due in February 2061 - 4.2%		0.1	$	0.1
Capital lease obligations		-		0.1
Total current portion of long-term debt	$	0.1	$	0.2

(a) Range of interest rates for the nine months ended September 30, 2014 and the twelve months ended December 31, 2013, respectively. 

At September 30, 2014, maturities of long-term debt are as follows:

Due within the twelve months ending September 30,
$ in millions
2015	$	0.1
2016		445.1
2017		0.1
2018		0.1
2019		0.1
Thereafter		432.1
		877.6
Unamortized discounts		(0.5)
Total long-term debt	$	877.1

On May 10, 2013, DP&L closed a  $300.0 million unsecured revolving credit agreement with a syndicated bank group. This $300.0 million facility has a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provides DP&Lthe ability to increase the size of the facility by an additional $100.0 million.  At September 30, 2014, there were two letters of credit in the amount of $0.7 million outstanding, with the remaining $299.3 million available to DP&L.  Fees associated with this revolving credit facility were not material during the three and nine months endedSeptember 30, 2014 or 2013.

DP&L’s unsecured revolving credit agreements and DP&L’s standby letter of credit have two financial covenants, the first measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter.  The second financial covenant compares EBITDA to Interest Expense.  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.

On March 31, 2014, DP&L borrowed $15.0 million from DPL at an interest rate of LIBOR plus 2.0%.  This note was due on or before April 30, 2014 and was repaid on April 30, 2014.

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Supplemental Financial Information (Tables)

9 Months Ended

Sep. 30, 2014

Schedule of Supplemental Financial Information

	September 30,		December 31,
$ in millions	2014		2013
Accounts receivable, net:
Unbilled revenue	$	65.7	$	77.8
Customer receivables		112.9		102.7
Amounts due from partners in jointly owned plants		10.4		15.8
Other		3.0		8.2
Provision for uncollectible accounts		(1.3)		(1.2)
Total accounts receivable, net	$	190.7	$	203.3
Inventories, at average cost:
Fuel and limestone	$	48.5	$	42.7
Plant materials and supplies		36.2		38.2
Other		1.7		1.8
Total inventories, at average cost	$	86.4	$	82.7

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Consolidated Statements of Operations	Three months ended				Nine months ended
		September 30,				September 30,
$ in millions		2014		2013		2014		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income	$	0.3	$	0.6	$	0.6	$	2.1
	Tax expense		(0.1)		(0.2)		(0.2)		(0.7)
	Net of income taxes		0.2		0.4		0.4		1.4
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.3)		-		(1.0)		-
	Revenue		4.9		0.5		23.4		2.2
	Purchased power		0.3		1.6		(0.8)		2.9
	Total before income taxes		4.9		2.1		21.6		5.1
	Tax expense		(1.5)		(0.8)		(7.4)		(2.1)
	Net of income taxes		3.4		1.3		14.2		3.0
Amortization of defined benefit pension items (Note 7):
	Tax benefit		-		-		-		0.3
	Net of income taxes		-		-		-		0.3
Total reclassifications for the period, net of income taxes		$	3.6	$	1.7	$	14.6	$	4.7

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, 2014	$	0.6	$	20.6	$	3.4	$	24.6
Other comprehensive loss before reclassifications		(0.6)		(23.8)		-		(24.4)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.4		14.2		-		14.6
Net current period other comprehensive loss		(0.2)		(9.6)		-		(9.8)
Balance September 30, 2014	$	0.4	$	11.0	$	3.4	$	14.8

DP&L [Member]

Schedule of Supplemental Financial Information

	September 30,		December 31,
$ in millions	2014		2013
Accounts receivable, net:
Unbilled revenue	$	36.0	$	47.2
Customer receivables		70.3		58.2
Amounts due from partners in jointly owned plants		10.4		15.8
Other		27.0		27.2
Provision for uncollectible accounts		(0.9)		(0.9)
Total accounts receivable, net	$	142.8	$	147.5
Inventories, at average cost:
Fuel and limestone	$	48.5	$	42.9
Plant materials and supplies		35.0		37.0
Other		1.7		1.8
Total inventories, at average cost	$	85.2	$	81.7

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended				Nine months ended
		September 30,				September 30,
$ in millions		2014		2013		2014		2013
Gains and losses on Available-for-sale securities activity (Note 8):
	Other income	$	0.3	$	0.6	$	0.6	$	2.1
	Tax expense		(0.1)		(0.2)		(0.2)		(0.7)
	Net of income taxes		0.2		0.4		0.4		1.4
Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.2)		(0.6)		(0.8)		(1.8)
	Revenue		4.9		0.4		23.4		2.1
	Purchased power		0.4		2.0		(0.6)		4.2
	Total before income taxes		5.1		1.8		22.0		4.5
	Tax expense		(1.9)		(0.8)		(6.7)		(2.2)
	Net of income taxes		3.2		1.0		15.3		2.3
Amortization of defined benefit pension items (Note 7):
	Reclassification to Other income / (deductions)		1.0		1.4		3.1		4.2
	Tax benefit		(0.3)		(0.5)		(1.0)		(1.5)
	Net of income taxes		0.7		0.9		2.1		2.7
Total reclassifications for the period, net of income taxes		$	4.1	$	2.3	$	17.8	$	6.4

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, 2014	$	0.8	$	6.2	$	(33.7)	$	(26.7)
Other comprehensive loss before reclassifications		(0.6)		(26.3)		-		(26.9)
Amounts reclassified from accumulated other comprehensive income / (loss)		0.4		15.3		2.1		17.8
Net current period other comprehensive loss		(0.2)		(11.0)		2.1		(9.1)
Balance September 30, 2014	$	0.6	$	(4.8)	$	(31.6)	$	(35.8)

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Fixed Asset Impairment

9 Months Ended

Sep. 30, 2014

Asset Impairment Charges [Abstract]

Fixed-asset Impairment

During the first quarter of 2014, DP&L tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L.  Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013.  DP&L performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach.  As a result, we recognized an asset impairment expense of $11.5 million.  In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend.  The sale price approximates the carrying value.  This transaction is expected to close by the end of 2014.

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2014

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 normal purchase/normal sale, cash flow hedges or marked to market each reporting period. 

At September 30, 2014,  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		17.4		-		17.4
Heating oil futures		Mark to Market	Gallons		672.0		-		672.0
Forward power contracts		Cash Flow Hedge	MWh		40.7		(3,543.0)		(3,502.3)
Forward power contracts		Mark to Market	MWh		2,320.0		(3,357.9)		(1,037.9)

At December 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		7.1		-		7.1
Heating oil futures		Mark to Market	Gallons		1,428.0		-		1,428.0
Forward power contracts		Cash Flow Hedge	MWh		140.4		(4,705.7)		(4,565.3)
Forward power contracts		Mark to Market	MWh		3,177.8		(2,883.1)		294.7

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 entered into interest rate derivative contracts to manage interest rate exposure related to borrowings of fixed-rate debt.  These interest rate derivative contracts were settled in the third quarter of 2013.  We do not hedge all interest rate exposure.  We reclassify gains and losses on interest rate derivative hedges out of AOCI and into earnings in those periods in which hedged interest payments occur.

The following tables provide information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months ended September 30, 2014 and 2013:

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(12.4)	$	18.8	$	(1.1)	$	12.8
Net gains / (losses) associated with current period hedging transactions		1.2		-		(0.2)		6.4
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.2)		-		-
Revenues		3.4		-		0.3		-
Purchased power		0.2		-		1.0		-
Ending accumulated derivative gain / (loss) in AOCI	$	(7.6)	$	18.6	$	-	$	19.2

	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	1.4	$	19.2	$	(3.0)	$	0.5
Net gains / (losses) associated with current period hedging transactions		(23.8)		-		-		18.7
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.6)		-		-
Revenues		15.4		-		1.3		-
Purchased power		(0.6)		-		1.7		-
Ending accumulated derivative gain / (loss) in AOCI	$	(7.6)	$	18.6	$	-	$	19.2
Portion expected to be reclassified to earnings in the next twelve months (a)	$	(7.3)	$	(0.6)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		27		0

(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 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, 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 or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or 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 is 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 present the amount and classification within the Condensed Consolidated Statements of Results of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2014 and 2013. 

For the three months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.3	$	(2.3)	$	(2.2)
Realized gain / (loss)		-		0.1		(2.1)		(2.0)
Total	$	(0.2)	$	0.4	$	(4.4)	$	(4.2)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Purchased power		-		0.4		(4.4)		(4.0)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	0.4	$	(4.4)	$	(4.2)

For the three months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain	$	0.1	$	1.3	$	0.1	$	1.5
Realized gain / (loss)		0.1		-		(0.8)		(0.7)
Total	$	0.2	$	1.3	$	(0.7)	$	0.8
Recorded in Income Statement: gain / (loss)
Purchased power	$	-	$	1.3	$	(0.7)	$	0.6
Fuel		0.1		-		-		0.1
O&M		0.1		-		-		0.1
Total	$	0.2	$	1.3	$	(0.7)	$	0.8

For the nine months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized loss	$	(0.3)	$	(1.2)	$	(6.0)	$	(7.5)
Realized gain / (loss)		0.1		0.7		(3.6)		(2.8)
Total	$	(0.2)	$	(0.5)	$	(9.6)	$	(10.3)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: loss
Purchased power		-		(0.5)		(9.6)		(10.1)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	(0.5)	$	(9.6)	$	(10.3)

For the nine months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.4	$	10.5	$	10.7
Realized gain		-		1.2		0.5		1.7
Total	$	(0.2)	$	1.6	$	11.0	$	12.4
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Purchased power		-		1.6		11.0		12.6
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	1.6	$	11.0	$	12.4

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. 

Fair Values of Derivative Instruments
at September 30, 2014
				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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.9	$	(0.9)	$	-	$	-
Forward power contracts	MTM		6.3		(5.4)		-		0.9
Heating oil	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.7		(0.6)		(0.1)		-
Forward power contracts	MTM		3.3		(2.5)		-		0.8
Total assets		$	11.2	$	(9.4)	$	(0.1)	$	1.7
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	12.0	$	(0.9)	$	(9.8)	$	1.3
Forward power contracts	MTM		10.2		(5.4)		(2.8)		2.0
Heating oil	MTM		0.1		-		(0.1)		-
FTRs	MTM		1.0		-		-		1.0
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.3		(0.6)		(0.7)		-
Forward power contracts	MTM		3.4		(2.6)		(0.7)		0.1
Total liabilities		$	28.0	$	(9.5)	$	(14.1)	$	4.4

Forward power contracts with a value of $0.1 million have been omitted from the above table as they had been, but no longer need to be, accounted for as derivatives at fair value.  These derivatives are being amortized to earnings over the remaining term of the associated forward contracts. 

Fair Values of Derivative Instruments
at December 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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2		-		-		0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

Forward power contracts with a short-term asset position of $0.9million and a long-term asset position of $0.1 million have been omitted from the above table as they had been, but no longer need to be, accounted for as derivatives at fair value.  These derivatives are being amortized to earnings over the remaining term of the associated forward contracts.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at September 30, 2014was $28.0million.  Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  If our debt does not maintain an investment grade credit rating, our counterparties to the derivative instruments could request immediate payment or immediate and full overnight collateralization of the MTM loss.  The MTM loss positions at September 30, 2014 were offset by $14.1 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 $9.5 million.  If our counterparties were to call for collateral, we could have to post collateral for the remaining $4.4 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 September 30, 2014,  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		17.4		-		17.4
Heating oil futures		Mark to Market	Gallons		672.0		-		672.0
Forward power contracts		Cash Flow Hedge	MWh		40.7		(3,543.0)		(3,502.3)
Forward power contracts		Mark to Market	MWh		2,320.0		(3,463.5)		(1,143.5)

At December 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		7.1		-		7.1
Heating oil futures		Mark to Market	Gallons		1,428.0		-		1,428.0
Forward power contracts		Cash Flow Hedge	MWh		140.4		(4,705.7)		(4,565.3)
Forward power contracts		Mark to Market	MWh		3,172.4		(2,888.5)		283.9

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 tables provide information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three and nine months endedSeptember 30, 2014 and 2013: 

	Three months ended				Three months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(14.0)	$	4.6	$	(1.9)	$	6.1
Net gains / (losses) associated with current period hedging transactions		1.4		-		(0.3)		-
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.2)		-		(0.6)
Revenues		3.2		-		0.3		-
Purchased power		0.2		-		1.3		-
Ending accumulated derivative gain / (loss) in AOCI	$	(9.2)	$	4.4	$	(0.6)	$	5.5

	Nine months ended				Nine months ended
	September 30, 2014				September 30, 2013
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	1.0	$	5.2	$	(4.7)	$	7.3
Net losses associated with current period hedging transactions		(26.3)		-		-		-
Net gains / (losses) reclassified to earnings
Interest expense		-		(0.8)		-		(1.8)
Revenues		16.6		-		1.4		-
Purchased power		(0.5)		-		2.7		-
Ending accumulated derivative gain / (loss) in AOCI	$	(9.2)	$	4.4	$	(0.6)	$	5.5
Portion expected to be reclassified to earnings in the next twelve months (a)	$	(7.2)	$	(1.1)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		27		0

(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 Condensed 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 Condensed Statements of Results of Operations on an accrual basis. 

Regulatory Assets and Liabilities 

In accordance with regulatory accounting under GAAP, a cost or loss that is probable of recovery in future rates should be deferred as a regulatory asset and revenue or 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 is 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 present the amount and classification within the Condensed Statements of Results of Operations or Condensed Balance Sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2014 and 2013:  

For the three months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.3	$	(2.7)	$	(2.6)
Realized gain / (loss)		-		0.1		(2.1)		(2.0)
Total	$	(0.2)	$	0.4	$	(4.8)	$	(4.6)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		(0.3)		(0.3)
Purchased power		-		0.4		(4.5)		(4.1)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	0.4	$	(4.8)	$	(4.6)

For the three months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	0.1	$	1.3	$	(0.1)	$	1.3
Realized gain / (loss)		0.1		-		(0.8)		(0.7)
Total	$	0.2	$	1.3	$	(0.9)	$	0.6
Recorded in Income Statement: gain / (loss)
Revenues	$	-	$	-	$	0.1	$	0.1
Purchased power		-		1.3		(1.0)		0.3
Fuel		0.1		-		-		0.1
O&M		0.1		-		-		0.1
Total	$	0.2	$	1.3	$	(0.9)	$	0.6

For the nine months ended September 30, 2014
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized loss	$	(0.3)	$	(1.2)	$	(5.7)	$	(7.2)
Realized gain / (loss)		0.1		0.7		(3.0)		(2.2)
Total	$	(0.2)	$	(0.5)	$	(8.7)	$	(9.4)
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		1.0		1.0
Purchased power		-		(0.5)		(9.7)		(10.2)
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	(0.5)	$	(8.7)	$	(9.4)

For the nine months ended September 30, 2013
$ in millions	Heating Oil		FTRs		Power		Total
Change in unrealized gain / (loss)	$	(0.2)	$	0.4	$	8.9	$	9.1
Realized gain		-		1.2		1.1		2.3
Total	$	(0.2)	$	1.6	$	10.0	$	11.4
Recorded on Balance Sheet:
Regulatory asset	$	(0.1)	$	-	$	-	$	(0.1)
Recorded in Income Statement: gain / (loss)
Revenues		-		-		0.2		0.2
Purchased power		-		1.6		9.8		11.4
Fuel		(0.1)		-		-		(0.1)
Total	$	(0.2)	$	1.6	$	10.0	$	11.4

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. 

Fair Values of Derivative Instruments
at September 30, 2014
				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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.9	$	(0.9)	$	-	$	-
Forward power contracts	MTM		6.5		(5.4)		-		1.1
Heating oil futures	MTM		-		-		-		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.7		(0.6)		(0.1)		-
Forward power contracts	MTM		3.6		(2.6)		-		1.0
Total assets		$	11.7	$	(9.5)	$	(0.1)	$	2.1
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	12.0	$	(0.9)	$	(9.8)	$	1.3
Forward power contracts	MTM		10.2		(5.4)		(2.8)		2.0
Heating oil futures	MTM		0.1		-		(0.1)		-
FTRs	MTM		1.0		-		-		1.0
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.3		(0.6)		(0.7)		-
Forward power contracts	MTM		3.4		(2.6)		(0.7)		0.1
Total liabilities		$	28.0	$	(9.5)	$	(14.1)	$	4.4

The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at December 31, 2013:

Fair Values of Derivative Instruments
at December 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		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.2)	$	-	$	0.3
Forward power contracts	MTM		4.9		(4.2)		-		0.7
FTRs	MTM		0.2						0.2
Heating oil futures	MTM		0.2		-		(0.2)		-
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		3.0		-		(3.0)		-
Forward power contracts	MTM		5.0		(0.3)		-		4.7
Total assets		$	13.8	$	(4.7)	$	(3.2)	$	5.9
Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	2.7	$	(0.2)	$	(2.3)	$	0.2
Forward power contracts	MTM		6.6		(4.2)		(2.3)		0.1
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	MTM		1.3		(0.3)		(1.0)		-
Total liabilities		$	10.6	$	(4.7)	$	(5.6)	$	0.3

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, 2014 was $28.0 million.  Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies.  If our debt does not maintain an investment grade credit rating, our counterparties to the derivative instruments could request immediate payment or immediate and full overnight collateralization of the MTM loss.  The MTM loss positions at September 30, 2014 were offset by $14.1 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 $9.5 million.  If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $4.4 million.

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Contractual Obligations, Commercial Commitments and Contingencies (Narative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		9 Months Ended							9 Months Ended													9 Months Ended
	Sep. 30, 2014 T	Sep. 30, 2013	Sep. 30, 2014 DP&L [Member] T	Dec. 31, 2013 DP&L [Member]	Sep. 30, 2014 Electric Generation Company [Member]	Sep. 30, 2014 DPLER [Member]	Sep. 30, 2013 DPLE [Member]	Sep. 30, 2014 MC Squared [Member]	Sep. 30, 2014 Beckjord Unit 6 [Member] DP&L [Member]	Sep. 30, 2014 Debt Obligation on 4.9% Equity Ownership [Member]	Sep. 30, 2014 Debt Obligation on 4.9% Equity Ownership [Member] DP&L [Member]	Sep. 30, 2014 Pollution Control Series Maturing in January 2028 - 4.70% [Member]	Sep. 30, 2014 Pollution Control Series Maturing in January 2028 - 4.70% [Member] DP&L [Member]	Sep. 30, 2014 Pollution Control Series Maturing in January 2034 - 4.80% [Member]	Sep. 30, 2014 Pollution Control Series Maturing in January 2034 - 4.80% [Member] DP&L [Member]	Sep. 30, 2014 Pollution Control Series Maturing in September 2036 - 4.80% [Member]	Sep. 30, 2014 Pollution Control Series Maturing in September 2036 - 4.80% [Member] DP&L [Member]	Sep. 30, 2014 U.S. Government note maturing in February 2061 - 4.20% [Member]	Sep. 30, 2014 U.S. Government note maturing in February 2061 - 4.20% [Member] DP&L [Member]	Sep. 30, 2014 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Sep. 30, 2014 Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Sep. 30, 2014 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Sep. 30, 2014 CO2 [Member]	Sep. 30, 2014 CO2 [Member] DP&L [Member]	Sep. 30, 2014 Interim goals[Member] lb	Sep. 30, 2014 Interim goals[Member] DP&L [Member] lb	Sep. 30, 2014 Final goals[Member] lb	Sep. 30, 2014 Final goals[Member] DP&L [Member] lb
Public Utility, Property, Plant and Equipment [Line Items]
Third party guarantees	$ 19.0					$ 2.0	$ 16.8	$ 0.2
Due to third parties, current	0.4
Equity ownership interest			4.90%							4.90%
Equity ownership interest aggregate cost										76.0	76.0
Debt obligation					1,550.1
Long Term Debt Date Range Equity Ownership, Start			2018							2018
Long Term Debt Date Range Equity Ownership, End			2040							2040
Debt instrument interest percentage												4.70%	4.70%	4.80%	4.80%	4.80%	4.80%	4.20%	4.20%	8.125%	6.50%	7.25%
Environmental reserves	$ 0.9	$ 1.1	$ 0.9	$ 1.1
Percentage of energy generated by coal	99.00%		99.00%
Emission Reductions																							30.00%	30.00%
Emission Reductions Ohio																							28	28
Annual CO2 emissions generation at stations, in tons	14,000,000		14,000,000
CO2 tons per megawatt-hour for USEPA standard on new EGUs																									1,452,000	1,452,000	1,338,000	1,338,000
Ownership (%)									50.00%

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Pension and Postretirement Benefits

9 Months Ended

Sep. 30, 2014

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 ERISA and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three and nine months endedSeptember 30, 2014 or 2013, respectively. 

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 and nine months ended September 30, 2014 and 2013 was: 

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended				Three months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	1.5	$	1.8	$	-	$	-
Interest cost		4.3		3.8		0.2		0.2
Expected return on plan assets (a)		(5.8)		(5.8)		-		-
Amortization of unrecognized:
Prior service cost		0.4		0.3		-		-
Actuarial loss / (gain)		0.9		1.3		(0.1)		(0.1)
Net periodic benefit cost	$	1.3	$	1.4	$	0.1	$	0.1

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	4.5	$	5.4	$	0.1	$	0.1
Interest cost		13.1		11.6		0.6		0.6
Expected return on plan assets (a)		(17.2)		(17.6)		(0.1)		(0.2)
Amortization of unrecognized:
Prior service cost		1.1		1.1		-		-
Actuarial loss / (gain)		2.6		3.7		(0.4)		(0.3)
Net periodic benefit cost	$	4.1	$	4.2	$	0.2	$	0.2

(a) For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used.  GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years.  We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the calculation of expected return on pension plan assets for the 2014 and 2013 net periodic benefit cost was approximately $351 million and $346 million, respectively. 

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions	Pension		Postretirement
2014	$	6.3	$	0.5
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

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 ERISA and, in addition, make voluntary contributions from time to time.  There were no contributions made during the three and nine months endedSeptember 30, 2014 or 2013, respectively.

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 and nine months endedSeptember 30, 2014 and 2013 was:

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended				Three months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	1.5	$	1.8	$	-	$	-
Interest cost		4.3		3.8		0.2		0.2
Expected return on plan assets (a)		(5.7)		(5.8)		(0.1)		(0.1)
Amortization of unrecognized:
Prior service cost		0.7		0.7		0.1		0.1
Actuarial loss / (gain)		1.6		2.3		(0.2)		(0.2)
Net periodic benefit cost	$	2.4	$	2.8	$	-	$	-

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	4.4	$	5.4	$	0.1	$	0.1
Interest cost		13.0		11.6		0.6		0.6
Expected return on plan assets (a)		(17.0)		(17.6)		(0.2)		(0.2)
Amortization of unrecognized:
Prior service cost		2.1		2.1		0.1		0.1
Actuarial loss / (gain)		4.8		6.9		(0.5)		(0.5)
Net periodic benefit cost	$	7.3	$	8.4	$	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 2014 and 2013 net periodic benefit cost was approximately $351 million and $346 million, respectively. 

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions	Pension		Postretirement
2014	$	6.3	$	0.5
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

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 September 30, 2014 and December 31, 2013.  Further information about the fair value of our derivative instruments can be found in Note 9.

	September 30, 2014				December 31, 2013
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.6		3.3		4.4
Debt securities		5.0		5.0		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total Assets	$	9.0	$	10.0	$	10.3	$	11.5
Liabilities
Debt	$	2,264.4	$	2,345.9	$	2,294.4	$	2,334.6

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 carrying value.

Debt 

The carrying value of DPL’s debt in place at the Merger was adjusted to fair value at the Merger date.  The carrying value of this debt is net of subsequent amortization of any premiums or discounts recognized at the merger date.  Debt issued subsequent to the Merger is carried at issue cost, net of unamortized premium or discount.  Unrealized gains or losses are not recognized in the financial statements because debt is presented at cost or 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 2016 to 2061. 

Master Trust Assets 

DP&L established Master Trusts 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 deferred assets on the balance sheets and classified as available for sale.  Any unrealized gains or losses are recorded in AOCI until the securities are sold. 

DPL had  $0.6 million($0.4million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2014 and $0.9 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses in AOCI at December 31, 2013. 

During the nine months ended September 30, 2014,  $0.6 million ($0.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  An immaterial amount of unrealized gains are expected to be reversed to earnings over the next twelve months to facilitate the distribution of benefits.

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 September 30, 2014 and December 31, 2013 and the respective category within the fair value hierarchy for DPL was determined as follows: 

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.1	$	0.1	$	-	$	-
Equity securities		3.6		3.6		-		-
Debt securities		5.0		5.0		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		10.0		9.1		0.9		-
Derivative Assets
Forward power contracts		11.2		-		11.2		-
Total Derivative assets		11.2		-		11.2		-
Total Assets	$	21.2	$	9.1	$	12.1	$	-
Liabilities
Derivative Liabilities
FTRs	$	1.0	$	-	$	-	$	1.0
Heating oil		0.1		0.1		-		-
Forward power contracts		26.9		-		26.9		-
Total Derivative liabilities		28.0		0.1		26.9		1.0
Long-term debt		2,345.9		-		2,327.6		18.3
Total Liabilities	$	2,373.9	$	0.1	$	2,354.5	$	19.3

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		11.5		10.6		0.9		-
Derivative assets
FTRs		0.2		-		-		0.2
Heating oil futures		0.2		0.2		-		-
Forward power contracts		13.4		-		13.4		-
Total Derivative assets		13.8		0.2		13.4		0.2
Total Assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Derivative liabilities
Forward power contracts	$	10.6	$	-		10.6	$	-
Total Derivative liabilities		10.6		-		10.6		-
Long-term debt		2,334.6		-		2,316.1		18.5
Total Liabilities	$	2,345.2	$	-	$	2,326.7	$	18.5

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).  FTRs 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. 

Approximately 98%  of the inputs to the fair value of our derivative instruments are from quoted market prices. 

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. 

Non-recurring Fair Value Measurements 

We use the cost approach to determine the fair value of our AROs, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  There was not a material change in our AROs in thethree months ended September 30, 2014.  AROs increased $1.6 million during the nine months ended September 30, 2014,primarily due to a new study of the asbestos and underground storage tank AROs at Hutchings in the first quarter of 2014.  Additions to AROs were not material during the three and nine months ended September 30, 2013.

When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance.  Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes Goodwill and Long-lived assets measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:

$ in millions	Nine months ended September 30, 2014
		Carrying	Fair Value							Gross
		Amount (c)		Level 1		Level 2		Level 3		Loss
Assets
Long-lived assets (a)
DP&L (East Bend)	$	14.2	$	-	$	-	$	2.7	$	11.5
Goodwill (b)
DPLER Reporting unit	$	135.8	$	-	$	-	$	-	$	135.8

(a)See Note 13 for further information

(b)See Note 12 for further information

(c)Carrying amount at date of valuation

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 September 30, 2014 and December 31, 2013.  Further information about the fair value of our derivative instruments can be found in Note 9.

	September 30, 2014				December 31, 2013
$ in millions	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.3	$	0.3
Equity securities		2.7		3.6		3.3		4.4
Debt securities		5.0		5.0		5.4		5.5
Hedge funds		0.8		0.9		0.9		0.9
Real estate		0.4		0.4		0.4		0.4
Total assets	$	9.0	$	10.0	$	10.3	$	11.5
Liabilities
Debt	$	877.1	$	884.7	$	877.1	$	859.6

These financial instruments are not subject to master netting agreements or collateral requirements and as such are presented in the Condensed 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 2016 to 2061. 

Master Trust Assets 

DP&L established Master Trusts 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 that 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. 

DP&L had $0.9 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2014 and $1.2 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2013. 

During the nine months endedSeptember 30, 2014,  $0.6 million $0.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings.  An immaterial amount of unrealized gains are expected to be reversed to earnings over the next twelve months to facilitate the disbursement of benefits.

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 September 30, 2014 and December 31, 2013 and the respective category within the fair value hierarchy for DP&L was determined as follows: 

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2014		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.1	$	0.1	$	-	$	-
Equity securities		3.6		3.6		-		-
Debt securities		5.0		5.0		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		10.0		9.1		0.9		-
Derivative assets
FTRs		-		-		-		-
Heating oil		-		-		-		-
Forward power contracts		11.7		-		11.7		-
Total derivative assets		11.7		-		11.7		-
Total assets	$	21.7	$	9.1	$	12.6	$	-
Liabilities
Derivative liabilities
FTRs	$	1.0	$	-	$	-	$	1.0
Heating oil		0.1		0.1		-		-
Forward power contracts		26.9		-		26.9		-
Total derivative liabilities		28.0		0.1		26.9		1.0
Long-term debt		884.7		-		866.4		18.3
Total liabilities	$	912.7	$	0.1	$	893.3	$	19.3

Assets and Liabilities at Fair Value
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2013		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust assets
Money market funds	$	0.3	$	0.3	$	-	$	-
Equity securities		4.4		4.4		-		-
Debt securities		5.5		5.5		-		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		0.4		-		-
Total Master Trust assets		11.5		10.6		0.9		-
Derivative assets
Heating oil futures		0.2		0.2		-		-
FTRs		0.2		-		-		0.2
Forward power contracts		13.4		-		13.4		-
Total Derivative assets		13.8		0.2		13.4		0.2
Total assets	$	25.3	$	10.8	$	14.3	$	0.2
Liabilities
Derivative liabilities
Forward power contracts		10.6		-		10.6		-
Total Derivative liabilities		10.6		-		10.6		-
Long-term debt		859.6		-		841.1		18.5
Total liabilities	$	870.2	$	-	$	851.7	$	18.5

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).  FTRs 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 98% 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 is estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates.  These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy.  There was not a material change in our AROs in the three months ended September 30, 2014.  Additions to AROs for the three and nine months ended September 30, 2014 were $1.7 million, primarily due to a new study of the asbestos and underground storage tank AROs at Hutchings in the first quarter of 2014.  Additions to AROs were not material during the three and nine months endedSeptember 30, 2013. 

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Contractual Obligations, Commercial Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

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, 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 September 30, 2014,  DPL  had $19.0 million of guarantees to third parties for future financial or performance assurance under such agreements:  $2.0 million of guarantees on behalf of DPLER, $16.8 million of guarantees on behalf of DPLE and $0.2 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 to the beneficiaries within a certain time. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.4 million at September 30, 2014. 

To date, DPL has not incurred any losses related to the guarantees of DPLER’s, DPLE’s or 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. 

DP&L – Equity Ownership Interest

DP&L owns a 4.9%  equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP.  As of September 30, 2014,  DP&L could be responsible for the repayment of 4.9%, or $76.0 million, of a $1,550.1 million debt obligation that has maturities from 2018 to 2040.  This would only happen if OVEC defaulted on its debt payments.  As of September 30, 2014, 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, 2013.

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 September 30, 2014, cannot be reasonably determined. 

Environmental Matters

DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws.  The environmental issues that may affect us include:

· The federal CAA and state laws and regulations (including the Ohio SIP) which require compliance, obtaining permits and reporting as to air emissions,

· Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,

· Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO₂, particulates, mercury, acid gases, NO_x, and other air emissions.  DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,

· Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and may require reductions of GHGs,

· Rules and future rules issued by the USEPA associated with the federal CWA, which prohibit the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

· Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.  The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the USEPA is reconsidering that determination and planning to finalize a new rule regulating coal combustion by-products.  A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such by-products.

In addition to 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 in an effort 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 September 30, 2014, and December 31, 2013, we had accruals of approximately $0.9 million and $1.1 million, respectively, for environmental matters and other claims.  We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated, which are disclosed in the paragraphs below.  We evaluate the potential liability related to environmental matters quarterly and may revise our accruals.  Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our EGUs and stations.  Some of these matters could have material adverse effects on the operation of the power stations.

Cross-State Air Pollution Rule

On April 29, 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) that had vacated CSAPR and remanded the case back to the D.C. Circuit Court.  On June 26, 2014, the U.S. Department of Justice, on behalf of the USEPA, filed a motion with the D.C. Circuit Court to lift the current stay on CSAPR which was granted on October 23, 2014.  The USEPA is expected to establish new effective dates for compliance with the reduced emissions levels, the first of which could take effect as early as January 2015.  Certain challenges to CSAPR by industry groups and states (including Ohio) remain pending and oral arguments have been scheduled for March 2015.  It is not possible to predict what impacts CSAPR and the pending litigation may have on our consolidated financial condition, results of operations or cash flows, but it is not expected to be material.

National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO₂ replacing the previous 24-hour standard and annual standard with a one-hour standard.  Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations recommended as non-attainment.  Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014, the USEPA proposed a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO₂ emissions.  The rule, if finalized, could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations.  DP&L is unable to determine the effect of the proposed rule on its operations.

Carbon Dioxide and Other Greenhouse Gas Emissions

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 set forth criteria for determining which facilities were required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  The U.S Supreme Court reviewed several cases addressing the USEPA’s authority to issue GHG PSD permits under Section 165 of the CAA, and on June 23, 2014 ruled that the USEPA had exceeded its statutory authority in issuing the Tailoring Rule.  However, the Supreme Court upheld the USEPA’s ability to include Best Available Control Technology (BACT) requirements for GHGs emitted by sources that are already subject to the PSD requirements for other pollutants.  Therefore, if future modifications to DP&L’s sources require PSD review for other pollutants, it may also trigger GHG BACT requirements.  The USEPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. 

The USEPA issued proposed GHG emissions rules for existing, modified and reconstructed generating units on June 2, 2014.  Under the proposed rules, called the Clean Power Plan, states would be judged against state-specific CO₂ emissions targets beginning in 2020, with an expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030.  For Ohio specifically, the Clean Power Plan proposes an interim goal for 2020-2029 and a proposed 2030 final goal of 1,452 pounds of CO₂ per megawatt hour and 1,338 pounds of CO₂ per megawatt hour, respectively, a reduction of approximately 28% from 2012 levels.  The proposed rule requires states to submit implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances.  The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures.  We could be required, among other things, to make efficiency improvements at our facilities.  USEPA expects to finalize this rule by June 1, 2015.  We cannot predict the effect of these proposed rules on DP&L’s operations. 

Approximately 99% of the energy we produce is generated by coal.  DP&L’s share of CO₂ emissions at generating stations we own and co-own is approximately 14 million tons annually.  Further GHG legislation or regulation implemented at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L. 

Clean Water Act – Regulation of Water Intake

On May 19, 2014, the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures.  The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  Although we do not yet know the full impact the final rules will have on our operations, the final rule may require material changes to the intake structure at Stuart Station to reduce impingement with the possibility of additional site specific requirements for reducing entrainment.  We do not believe the final rule will have a material impact on operations at any of the other DP&L facilities.

A final NPDES permit for Killen Station was issued on September 4, 2014.  We do not expect the new permit to have a material impact on Killen’s operations.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (“ASAOC”) was executed and became effective among a group of PRPs, not including DP&L, and the USEPA. 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 the PRP group in performing an RI/FS under the August 15, 2006 ASAOC. That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th Circuit affirmed the lower court’s ruling and subsequently denied a request by the plaintiffs for rehearing.DP&L cannot predict whether the plaintiffs will appeal to the U.S. Supreme Court.DP&L is unable to predict the outcome of any such action by the plaintiffs. Additionally, the Court’s ruling and the Appeal Court affirmance of that 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.

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 OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP.  As of September 30, 2014,  DP&L could be responsible for the repayment of 4.9%, or $76.0 million, of a $1,550.1 million debt obligation that has maturities from 2018 to 2040.  This would only happen if OVEC defaulted on its debt payments.  As of September 30, 2014, 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, 2013.

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 September 30, 2014, cannot be reasonably determined. 

Environmental Matters

DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws.  The environmental issues that may affect us include:

· The federal CAA and state laws and regulations (including the Ohio SIP) which require compliance, obtaining permits and reporting as to air emissions,

· Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,

· Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO₂, particulates, mercury, acid gases, NO_x, and other air emissions.  DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,

· Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and may require reductions of GHGs,

· Rules and future rules issued by the USEPA associated with the federal CWA, which prohibit the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

· Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.  The USEPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the USEPA is reconsidering that determination and planning to propose a new rule regulating coal combustion by-products.  A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such by-products.

In addition to 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 our facilities in an effort 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 September 30, 2014, and December 31, 2013, we had accruals of approximately $0.9 million and $1.1 million, respectively, for environmental matters and other claims.  We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated, which are disclosed in the paragraphs below.  We evaluate the potential liability related to 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 condition or cash flows.

We have several pending environmental matters associated with our EGUs and stations.  Some of these matters could have material adverse effects on the operation of the power stations.  

Cross-State Air Pollution Rule

On April 29, 2014, the U.S. Supreme Court reversed a 2012 decision by the U.S. Court of Appeals for the District of Columbia (D.C. Circuit Court) that had vacated CSAPR and remanded the case back to the D.C. Circuit Court.  On June 26, 2014, the U.S. Department of Justice, on behalf of the USEPA, filed a motion with the D.C. Circuit Court to lift the current stay on CSAPR which was granted on October 23, 2014.  The USEPA is expected to establish new effective dates for compliance with the reduced emissions levels, the first of which could take effect as early as January 2015.  Certain challenges to CSAPR by industry groups and states (including Ohio) remain pending and oral arguments have been scheduled for March 2015.  It is not possible to predict what impacts CSAPR and the pending litigation may have on our consolidated financial condition, results of operations or cash flows, but it is not expected to be material.

National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO₂ replacing the previous 24-hour standard and annual standard with a one-hour standard.  Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations recommended as non-attainment.  Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014, the USEPA proposed a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO₂ emissions.  The rule, if finalized, could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations.  DP&L is unable to determine the effect of the proposed rule on its operations.

Carbon Dioxide and Other Greenhouse Gas Emissions

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 set forth criteria for determining which facilities were required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  The U.S Supreme Court reviewed several cases addressing the USEPA’s authority to issue GHG PSD permits under Section 165 of the CAA, and on June 23, 2014 ruled that the USEPA had exceeded its statutory authority in issuing the Tailoring Rule.  However, the Supreme Court upheld the USEPA’s ability to include Best Available Control Technology (BACT) requirements for GHGs emitted by sources that are already subject to the PSD requirements for other pollutants.  Therefore, if future modifications to DP&L’s sources require PSD review for other pollutants, it may also trigger GHG BACT requirements.  The USEPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis.

The USEPA issued proposed GHG emissions rules for existing, modified and reconstructed generating units on June 2, 2014.  Under the proposed rules, called the Clean Power Plan, states would be judged against state-specific CO₂ emissions targets beginning in 2020, with an expected total U.S. power sector emissions reduction of 30% from 2005 levels by 2030.  For Ohio specifically, the Clean Power Plan proposes an interim goal for 2020-2029 and a proposed 2030 final goal of 1,452 pounds of CO₂ per megawatt hour and 1,338 pounds of CO₂ per megawatt hour, respectively, a reduction of approximately 28% from 2012 levels.  The proposed rule requires states to submit implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one- or two-year extensions under certain circumstances.  The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures.  We could be required, among other things, to make efficiency improvements at our facilities.  USEPA expects to finalize this rule by June 1, 2015.  We cannot predict the effect of these proposed rules on DP&L’s operations.

Approximately 99% of the energy we produce is generated by coal.  DP&L’s share of CO₂ emissions at generating stations we own and co-own is approximately 14 million tons annually.  Further GHG legislation or regulation implemented at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition.  However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L. 

Clean Water Act – Regulation of Water Intake

On May 19, 2014, the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures.  The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal.  Although we do not yet know the full impact the final rules will have on our operations, the final rule may require material changes to the intake structure at Stuart Station to reduce impingement with the possibility of additional site specific requirements for reducing entrainment.  We do not believe the final rule will have a material impact on operations at any of the other DP&L facilities.

A final NPDES permit for Killen Station was issued on September 4, 2014.  We do not expect the new permit to have a material impact on Killen’s operations.

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site.  In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach.  In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS.  No recent activity has occurred with respect to that notice or PRP status.  On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (“ASAOC”) was executed and became effective among a group of PRPs, not including DP&L, and the USEPA.  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 the PRP group in performing an RI/FS under the August 15, 2006 ASAOC.  That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th Circuit affirmed the lower court’s ruling and subsequently denied a request by the plaintiffs for rehearing.  DP&L cannot predict whether the plaintiffs will appeal to the U.S. Supreme Court.  DP&L is unable to predict the outcome of any such action by the plaintiffs.  Additionally, the Court’s ruling and the Appeal Court affirmance of that 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. 

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Fixed-asset Impairment (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Carrying Value	$ 2,501.4	$ 2,534.2
Fixed asset impairment	11.5
Parent Company [Member]
Fixed asset impairment	11.5
East Bend Station [Member]
Fair Value	2.7
Fixed asset impairment	$ 11.5
Production Plan Capacity	186

XML

Goodwill Impairment (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Goodwill Impairment		$ 135.8		$ 135.8
Goodwill	317.0			317.0		452.8
Effective Income Tax Rate, Continuing Operations	(71.50%)		25.40%	(34.20%)	21.50%
Parent Company [Member]
Goodwill Impairment				135.8
DP&L [Member]
Effective Income Tax Rate, Continuing Operations	19.80%		24.40%	23.20%	22.50%
DPLER [Member]
Goodwill Impairment				$ 135.8

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Summary of Significant Accounting Policies (Sale of Receivables) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
ComEd [Member]
Proceeds from Sale of Other Receivables	$ 27.1	$ 22.6	$ 68.3	$ 57.8
Duke Energy [Member]
Proceeds from Sale of Other Receivables	$ 10.6	$ 6.1	$ 30.4	$ 15.6

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Fair Value Measurements (Fair Value and Cost of Non-Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
DP&L [Member]
Total Master Trust Assets, Cost	$ 9.0	$ 10.3
Total Master Trust Assets, Fair Value	10.0	11.5
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost		10.3
Total Assets	9.0
Fair Value [Member]
Total Assets	10.0	11.5
Equity Securities [Member] | DP&L [Member]
Total Master Trust Assets, Cost	2.7	3.3
Total Master Trust Assets, Fair Value	3.6	4.4
Equity Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	2.7	3.3
Equity Securities [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	3.6	4.4
Debt Securities [Member] | DP&L [Member]
Total Master Trust Assets, Cost	5.0	5.4
Total Master Trust Assets, Fair Value	5.0	5.5
Money Market Funds [Member] | DP&L [Member]
Total Master Trust Assets, Cost	0.1	0.3
Total Master Trust Assets, Fair Value	0.1	0.3
Money Market Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.1	0.3
Money Market Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.1	0.3
Debt [Member] | DP&L [Member]
Debt, Cost	877.1	877.1
Debt, Fair Value	884.7	859.6
Debt [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	5.0	5.4
Debt, Cost	2,264.4	2,294.4
Debt [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	5.0	5.5
Debt, Fair Value	2,345.9	2,334.6
Hedge Funds [Member] | DP&L [Member]
Total Master Trust Assets, Cost	0.8	0.9
Total Master Trust Assets, Fair Value	0.9	0.9
Hedge Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.8	0.9
Hedge Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	0.9	0.9
Real Estate Funds [Member] | DP&L [Member]
Total Master Trust Assets, Cost	0.4	0.4
Total Master Trust Assets, Fair Value	0.4	0.4
Real Estate Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.4	0.4
Real Estate Funds [Member] | Fair Value [Member]
Total Master Trust Assets, Fair Value	$ 0.4	$ 0.4

XML

Summary of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2014

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.  The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES.  Following the Merger, DPL became an indirectly wholly owned subsidiary of AES.

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated.  DP&L has the exclusive right to provide such distribution and transmission services to its more than 515,000 customers located in West Central Ohio.  Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense.  DP&L's sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity.  DP&L sells any excess energy and capacity into the wholesale market.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.  DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.

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.  DPLER has approximately 274,000 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 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 our subsidiaries and us.  DPLowns all of the common stock of its subsidiaries. 

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 1,197 people as of September 30, 2014, of which 1,142 were employed by DP&L.  Approximately 61% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.The current collective bargaining agreement was ratified by the membership on October 30, 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 has undivided ownership interests in seven coal-fired and peaking generating facilities as well as numerous transmission facilities,all of which 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 Statements of Results 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, 2013. 

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 September 30, 2014; our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013.  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 EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014. 

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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits; goodwill; and intangibles. 

As a result of push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value.

Goodwill Impairment

Goodwill Impairment

In connection with the Merger, DPL re-measured 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.  DPL’s annual testing date for goodwill is October 1 of each year.  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 certain events, 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 

DPLER sells receivables from its customers in Duke Energy’s territory to Duke Energy.  Receivables sold to Duke Energy during the three months ended September 30, 2014 and 2013 were $10.6 million and $6.1 million, respectively.  Receivables sold to Duke Energy during the nine months ended September 30, 2014 and 2013 were $30.4 million and $15.6 million, respectively.  Similarly, MC Squared sells receivables from its customers in ComEd territory to ComEd.  Receivables sold to ComEd during the three months ended September 30, 2014 and 2013 were $27.1 million and $22.6 million, respectively.  Receivables sold to ComEd during the ninemonths ended September 30, 2014 and 2013 were $68.3 million and $57.8 million, respectively. There is no recourse or any other continuing involvement associated with the sold receivables.These sales are at face value for cash at the amounts billed for DPLER or MC Squared customers’ use of energy

Property, Plant and Equipment

Property, Plant & 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 except for adjustments of generating plants to fair market value recorded in connection with the Merger, subsequent impairments and the adjustment of certain intangible assets to fair market value in connection with the 2011 acquisition of MC Squared by DPLER. 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. 

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. 

Regulatory Accounting

Regulatory Accounting

As a regulated utility, DP&L applies the provisions of FASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory assets can also represent performance incentives permitted by the regulator, such as with our Energy Efficiency Shared Savings.  Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices.  Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DPL expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable.  In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment.  To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.  Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs.  It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval.  Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.  See Note 3 for more information about Regulatory Assets.

Intangibles

Intangibles 

Intangibles include emission allowances, renewable energy credits, customer relationships and customer contracts.  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 and nine months ended September 30, 2014 and 2013, gains from the sale of emission allowances were immaterial. 

Customer relationships recognized as part of the purchase accounting associated with the Merger are amortized over ten to seventeen years and customer contracts were amortized over the average length of the contracts.  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 not included in revenue.  The amounts of such taxes collected for the three months ended September 30, 2014 and 2013 were $12.5 million and $13.0 million, respectively.  The amounts of such taxes collected for theninemonths ended September 30, 2014 and 2013 were $38.5 million and $38.0 million, respectively.

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Issued Accounting Standards

Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016.  ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.  There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.  This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application.  The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns.  Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.  We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” effective for annual and interim periods beginning after December 15, 2014.  ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results.  In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes.  For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes.  Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact on our overall results of operations, financial position or cash flows.

Related Party Transactions

Related Party Transactions 

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L.  The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations.  This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Transactions with the Service Company
Charges for services provided	$	5.5	$	-	$	27.8	$	-
Charges to the Service Company		0.2		-		0.2		-

Transactions with the Service Company	At September 30, 2014		At December 31, 2013
Net prepaid / (payable) to the Service Company	$	9.4	$	-

DPL has issued debt to a wholly owned business trust, DPL Capital Trust II.

DP&L [Member]

Description of Business

Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio.  Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated.  DP&L has the exclusive right to provide such distribution and transmission services to its more than 515,000 customers located in West Central Ohio.  Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost.  During 2014, DP&L is required to source 10% of the generation for its SSO customers through a competitive bid process, 60% in 2015 and 100% in 2016.  Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense.  DP&L's sales reflect the general economic conditions, seasonal weather patterns,retail competition in our service territory  and the market price of electricity.  DP&L sells any excess energy and capacity into the wholesale market.  On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the time by which DP&L must separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.  While the OCC filed an application for rehearing on this Commission Order, it was denied by final order issued on July 23, 2014.  DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.DP&L is a subsidiary of DPL. 

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 1,142 people as of September 30, 2014.  Approximately 63% of all employees are under a collective bargaining agreement which expires on October 31, 2017.  The current collective bargaining agreement was ratified by the membership on October 30, 2014.

Financial Statement Presentation

Financial Statement Presentation

DP&L does not have any subsidiaries.  DP&L has undivided ownership interests in seven coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of 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 Statements of Results 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, 2013. 

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 September 30, 2014; our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the nine months ended September 30, 2014 and 2013.  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 EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2014 may not be indicative of our results that will be realized for the full year ending December 31, 2014. 

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; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; intangibles and assets and liabilities related to employee benefits.

Property, Plant and Equipment

Property, Plant & 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 except for the impact of asset impairments recorded for certain generating plants.  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. 

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

Regulatory Accounting

Regulatory Accounting

As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations,”which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates.  Regulatory assets can also represent performance incentives permitted by the regulator, such as with our CCEM energy efficiency program.  Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices.  Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable.  In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment.  To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.  Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs.  It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval.  Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.  See Note 3 for more information about Regulatory Assets.

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 and nine months ended September 30, 2014 and 2013, gains from the sale of emission allowances were immaterial.

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 not included in revenue.  The amounts of such taxes collected for the three months ended September 30, 2014 and 2013 were $12.5 million and $13.0 million, respectively.  The amounts of such taxes collected for the nine months ended September 30, 2014 and 2013 were $38.5 million and $38.0 million, respectively.

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Issued Accounting Standards

Going Concern

The FASB recently issued ASU 2014-15 “Presentation of Financial Statements – Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016.  ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued.  There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.  This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

Revenue from Contracts with Customers

The FASB recently issued ASU 2014-09 “Revenue from Contracts with Customers” (Topic 606) effective for annual and interim periods beginning after December 15, 2016; with retrospective application.  The core principle of the ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  Because the guidance in this update is principles-based, it can be applied to all contracts with customers regardless of industry-specific or transaction-specific fact patterns.  Additionally, the guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized.  We have not yet determined the extent, if any, to which our overall results of operations, financial position or cash flows may be affected by the implementation of this ASU.

Discontinued Operations

The FASB recently issued ASU 2014-08 “Presentation of Financial Statements” (Topic 205) and “Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” effective for annual and interim periods beginning after December 15, 2014.  ASU 2014-08 updates the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results.  In addition, an entity is required to expand disclosures for discontinued operations by providing more information about the assets, liabilities, revenues and expenses of discontinued operations both on the face of the financial statements and in the Notes.  For the disposal of an individually significant component of an entity that does not qualify for discontinued operations reporting, an entity is required to disclose the pretax profit or loss of the component in the Notes.  Our early adoption of ASU No. 2014-008 in the third quarter of 2014 did not have any impact on our overall results of operations, financial position or cash flows.

Related Party Transactions

Related Party Transactions 

In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company is to provide services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DP&L.  The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations.  This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of non-regulated businesses.

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

	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
DP&L Revenues:
Sales to DPLER (including MC Squared) (a)	$	125.6	$	123.8	$	376.6	$	336.0
DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(0.7)	$	(0.7)	$	(2.1)	$	(2.2)
Expense recoveries for services provided to DPLER (c)	$	0.5	$	1.3	$	1.6	$	3.8
Transactions with the Service Company
Charges for services provided	$	9.0	$	-	$	28.1	$	-

DP&L Customer security deposits:	At September 30, 2014		At December 31, 2013
Deposits received from DPLER (d)	$	20.1	$	19.2
Balances with the Service Company
Net prepaid / (payable) to the Service Company	$	9.4	$	-

(a)DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers.  The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the nine months endedSeptember 30, 2014, compared to the nine months endedSeptember 30, 2013, is primarily due to an increase in customers.

(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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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2014

Effective Income Tax Rates

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	2014	2013
DPL	(71.5)%	25.4%	(34.2)%	21.5%

DP&L [Member]

Effective Income Tax Rates

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	2014	2013
DP&L	19.8%	24.4%	23.2%	22.5%

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Pension and Postretirement Benefits (Estimated Future Benefit Payments and Medicare Part D Reimbursements) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Pension [Member]
2014	$ 6.3
2015	23.9
2016	23.9
2017	24.3
2018	24.6
2019 - 2022	126.5
Postretirement [Member]
2014	0.5
2015	2.1
2016	2.0
2017	1.8
2018	1.6
2019 - 2022	6.7
DP&L [Member] | Pension [Member]
2014	6.3
2015	23.9
2016	23.9
2017	24.3
2018	24.6
2019 - 2022	126.5
DP&L [Member] | Postretirement [Member]
2014	0.5
2015	2.1
2016	2.0
2017	1.8
2018	1.6
2019 - 2022	$ 6.7

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Ownership of Coal-fired Facilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Construction work in process	$ 19.0
Impairment of Long-Lived Assets Held-for-use	11.5
DP&L [Member]
Construction work in process	$ 19.0
Number Of Generating Facilities	7

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities:
Net income	$ (116.8)	$ 76.0
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	103.7	99.0
Amortization of intangibles	0.9	5.3
Amortization of debt market value adjustments	0.1	(14.3)
Deferred income taxes	(2.5)	31.5
Fixed asset impairment	11.5
Goodwill Impairment	135.8
Changes in certain assets and liabilities:
Accounts receivable	12.7	30.8
Inventories	(3.6)	18.6
Prepaid taxes	0.5	0.7
Taxes applicable to subsequent years	52.1	52.1
Deferred regulatory costs, net	4.8	11.6
Accounts payable	7.2	(7.2)
Accrued taxes payable	(27.5)	(69.3)
Accrued interest payable	14.5	24.3
Pension, retiree and other benefits	(5.2)	7.1
Unamortized investment tax credit	(0.4)	(0.4)
Insurance and claims costs	0.4	(2.4)
Other	(13.8)	(14.3)
Net cash provided by operating activities	174.4	249.1
Cash flows from investing activities:
Capital expenditures	(81.6)	(96.5)
Proceeds from sale of property - other		0.8
Insurance proceeds		7.6
Decrease (increase) in Restricted Cash	(9.0)	3.4
Other investing activities, net	1.1	(1.6)
Net cash used for investing activities	(93.1)	(89.6)
Cash flows from financing activities:
Deferred Finance Costs	(0.3)	(11.6)
Payment of long-term debt	(30.1)	(425.1)
Issuance of long-term debt		644.2
Withdrawals from revolving credit facilities	115.0	50.0
Repayments of borrowings from revolving credit facilities	(115.0)	(50.0)
Net cash used for financing activities	(30.4)	207.5
Cash and cash equivalents:
Net change	50.9	367.0
Balance at beginning of period	53.2	192.1
Cash and cash equivalents at end of period	104.1	559.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	73.8	79.5
Income taxes paid/(refund), net	0.2	(20.2)
Non-cash financing and investing activities:
Accruals for capital expenditures	6.7	5.4
THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from operating activities:
Net income	76.5	101.4
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	108.2	104.5
Deferred income taxes	2.9	27.1
Changes in certain assets and liabilities:
Accounts receivable	4.8	30.7
Inventories	(3.5)	18.5
Prepaid taxes	0.2	0.8
Taxes applicable to subsequent years	50.5	50.0
Deferred regulatory costs, net	4.8	12.4
Accounts payable	7.9	(7.3)
Accrued taxes payable	(40.8)	(48.2)
Accrued interest payable	(5.7)	2.7
Pension, retiree and other benefits	(5.2)	7.1
Unamortized investment tax credit	(1.9)	(1.9)
Other	(9.5)	(13.9)
Net cash provided by operating activities	189.2	283.9
Cash flows from investing activities:
Capital expenditures	(78.6)	(95.1)
Proceeds from sale of property - other		0.8
Insurance proceeds	0.4	12.1
Decrease (increase) in Restricted Cash	(9.4)	3.4
Other investing activities, net	1.1	(1.7)
Net cash used for investing activities	(90.1)	(83.8)
Cash flows from financing activities:
Dividends paid on common stock	(90.0)	(155.0)
Dividends paid on preferred stock	(0.7)	(0.6)
Borrowings from related party	15.0
Repayment of borrowings from related party	(15.0)
Deferred Finance Costs	(0.2)	(6.7)
Payment of long-term debt	(0.1)	(0.1)
Issuance of long-term debt		444.2
Net cash used for financing activities	(91.0)	281.8
Cash and cash equivalents:
Net change	8.1	481.9
Balance at beginning of period	22.9	28.5
Cash and cash equivalents at end of period	31.0	510.4
Supplemental cash flow information:
Interest paid, net of amounts capitalized	26.1	28.7
Income taxes paid/(refund), net	0.2	(20.3)
Non-cash financing and investing activities:
Accruals for capital expenditures	6.7	5.4
Emission Allowances [Member]
Cash flows from investing activities:
Payments to Acquire Intangible Assets	(0.2)
Emission Allowances [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from investing activities:
Payments to Acquire Intangible Assets	0.2
Renewable Energy Certificates [Member]
Cash flows from investing activities:
Payments to Acquire Intangible Assets	(3.4)	(3.3)
Renewable Energy Certificates [Member] | THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from investing activities:
Payments to Acquire Intangible Assets	$ 3.4	$ 3.3

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Ownership of Coal-fired Facilities

9 Months Ended

Sep. 30, 2014

Ownership of Coal-fired Facilities

4.  Ownership of Coal-fired Facilities 

DP&L has undivided ownership interests in seven coal-fired electric generating facilities, various peaking facilitiesand numerous transmission facilities with certain other Ohio utilities.  Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage.  The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  At September 30, 2014,  DP&L had  $19.0 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 at September 30, 2014 is as follows: 

	DP&L Share			DPL Carrying value
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	$	2	$	1	$	-	No
Conesville Unit 4	16.5	129		24		1		-	Yes
East Bend Station	31.0	186		-		-		-	Yes
Killen Station	67.0	402		309		17		2	Yes
Miami Fort Units 7 and 8	36.0	368		213		21		1	Yes
Stuart Station	35.0	808		213		15		12	Yes
Zimmer Station	28.1	365		181		33		4	Yes
Transmission (at varying percentages)		n/a		42		5		-
Total		2,465	$	984	$	93	$	19

Beckjord Unit 6, in which DP&L has a 50% ownership interest, is currently inoperable, and there are no plans to return it to service.  This unit was retired effective October 1, 2014.

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

As discussed in Note 13, we have reached an agreement to sell our interest in the East Bend station.

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, various peaking facilitiesand 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 September 30, 2014,  DP&L had $19.0 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 & 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 at September 30, 2014, is as follows: 

	DP&L Share			DP&L Carrying value
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	$	74	$	-	No
Conesville Unit 4	16.5	129		22		3		-	Yes
East Bend Station	31.0	186		2		1		-	Yes
Killen Station	67.0	402		624		311		2	Yes
Miami Fort Units 7 and 8	36.0	368		361		159		1	Yes
Stuart Station	35.0	808		751		319		12	Yes
Zimmer Station	28.1	365		1,100		670		4	Yes
Transmission (at varying percentages)		n/a		98		62		-
Total		2,465	$	3,034	$	1,599	$	19

Beckjord Unit 6, in which DP&L has a 50% ownership interest, is currently inoperable, and there are no plans to return it to service.  This unit was retired effective October 1, 2014.

In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend.  This transaction is expected to close by the end of 2014.

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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		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Change in unrealized gain / (loss)	$ (2.2)	$ 1.5	$ (7.5)	$ 10.7
Gain (Loss) on Derivative Instruments, Net, Pretax	(2.0)	(0.7)	(2.8)	1.7
Regulatory (asset)/liability				(0.1)
Derivative, Gain (Loss) on Derivative, Net	(4.2)	0.8	(10.3)	12.4
Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	0.3	1.3	(1.2)	0.4
Gain (Loss) on Derivative Instruments, Net, Pretax	0.1		0.7	1.2
Derivative, Gain (Loss) on Derivative, Net	0.4	1.3	(0.5)	1.6
Commodity Contract - Heating Oil [Member]
Change in unrealized gain / (loss)	(0.2)	0.1	(0.3)	(0.2)
Gain (Loss) on Derivative Instruments, Net, Pretax		0.1	0.1
Regulatory (asset)/liability				(0.1)
Derivative, Gain (Loss) on Derivative, Net	(0.2)	0.2	(0.2)	(0.2)
Forward Contract Power [Member]
Change in unrealized gain / (loss)	(2.3)	0.1	(6.0)	10.5
Gain (Loss) on Derivative Instruments, Net, Pretax	(2.1)	(0.8)	(3.6)	0.5
Derivative, Gain (Loss) on Derivative, Net	(4.4)	(0.7)	(9.6)	11.0
DP&L [Member]
Change in unrealized gain / (loss)	(2.6)	1.3	(7.2)	9.1
Gain (Loss) on Derivative Instruments, Net, Pretax	(2.0)	(0.7)	(9.4)	2.3
Regulatory (asset)/liability				(0.1)
Derivative, Gain (Loss) on Derivative, Net	(4.6)	0.6	(2.2)	11.4
DP&L [Member] | NYMEX Coal Contract [Member]
Change in unrealized gain / (loss)			(0.3)	(0.2)
Gain (Loss) on Derivative Instruments, Net, Pretax			(0.2)
Regulatory (asset)/liability				(0.1)
Derivative, Gain (Loss) on Derivative, Net			0.1	(0.2)
DP&L [Member] | Commodity Contract - FTR [Member]
Change in unrealized gain / (loss)	0.3	1.3		8.9
Gain (Loss) on Derivative Instruments, Net, Pretax	0.1			1.1
Derivative, Gain (Loss) on Derivative, Net	0.4	1.3		10.0
DP&L [Member] | Commodity Contract - Heating Oil [Member]
Change in unrealized gain / (loss)	(0.2)	0.1	(1.2)	0.4
Gain (Loss) on Derivative Instruments, Net, Pretax		0.1	(0.5)	1.2
Derivative, Gain (Loss) on Derivative, Net	(0.2)	0.2	0.7	1.6
DP&L [Member] | Forward Contract Power [Member]
Change in unrealized gain / (loss)	(2.7)	(0.1)	(5.7)
Gain (Loss) on Derivative Instruments, Net, Pretax	(2.1)	(0.8)	(8.7)
Derivative, Gain (Loss) on Derivative, Net	(4.8)	(0.9)	(3.0)
Revenue [Member] | DP&L [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.3)	0.1	1.0	0.2
Revenue [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net				0.2
Revenue [Member] | DP&L [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.3)	0.1	1.0
Fuel [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.1	(0.1)	(0.1)
Fuel [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.1	(0.1)	(0.1)
Fuel [Member] | DP&L [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.1	(0.1)	(0.1)
Fuel [Member] | DP&L [Member] | NYMEX Coal Contract [Member]
Derivative, Gain (Loss) on Derivative, Net			(0.1)	(0.1)
Fuel [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net	(0.1)	0.1
O&M [Member]
Derivative, Gain (Loss) on Derivative, Net		0.1
O&M [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		0.1
O&M [Member] | DP&L [Member]
Derivative, Gain (Loss) on Derivative, Net		0.1
O&M [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net		0.1
Purchased Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(4.0)	0.6	(10.1)	12.6
Purchased Power [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	0.4	1.3	(0.5)	1.6
Purchased Power [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(4.4)	(0.7)	(9.6)	11.0
Purchased Power [Member] | DP&L [Member]
Derivative, Gain (Loss) on Derivative, Net	(4.1)	0.3	(10.2)	11.4
Purchased Power [Member] | DP&L [Member] | Commodity Contract - FTR [Member]
Derivative, Gain (Loss) on Derivative, Net	0.4	1.3		9.8
Purchased Power [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Derivative, Gain (Loss) on Derivative, Net			(0.5)	1.6
Purchased Power [Member] | DP&L [Member] | Forward Contract Power [Member]
Derivative, Gain (Loss) on Derivative, Net	(4.5)	(1.0)	(9.7)
Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(0.1)		(0.1)
Regulatory Asset Liability [Member] | Commodity Contract - Heating Oil [Member]
Regulatory (asset)/liability	(0.1)		(0.1)
Regulatory Asset Liability [Member] | DP&L [Member]
Regulatory (asset)/liability			(0.1)
Regulatory Asset Liability [Member] | DP&L [Member] | NYMEX Coal Contract [Member]
Regulatory (asset)/liability			(0.1)
Not Designated as Hedging Instrument [Member] | Regulatory Asset Liability [Member] | DP&L [Member]
Regulatory (asset)/liability	(0.1)
Not Designated as Hedging Instrument [Member] | Regulatory Asset Liability [Member] | DP&L [Member] | Commodity Contract - Heating Oil [Member]
Regulatory (asset)/liability	$ (0.1)

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Pension and Postretirement Benefits (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2014

Sep. 30, 2014

Net Periodic Benefit Cost / (Income)

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended				Three months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	1.5	$	1.8	$	-	$	-
Interest cost		4.3		3.8		0.2		0.2
Expected return on plan assets (a)		(5.8)		(5.8)		-		-
Amortization of unrecognized:
Prior service cost		0.4		0.3		-		-
Actuarial loss / (gain)		0.9		1.3		(0.1)		(0.1)
Net periodic benefit cost	$	1.3	$	1.4	$	0.1	$	0.1

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	4.5	$	5.4	$	0.1	$	0.1
Interest cost		13.1		11.6		0.6		0.6
Expected return on plan assets (a)		(17.2)		(17.6)		(0.1)		(0.2)
Amortization of unrecognized:
Prior service cost		1.1		1.1		-		-
Actuarial loss / (gain)		2.6		3.7		(0.4)		(0.3)
Net periodic benefit cost	$	4.1	$	4.2	$	0.2	$	0.2

Estimated Future Benefit Payments and Medicare Part D Reimbursements

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions	Pension		Postretirement
2014	$	6.3	$	0.5
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

DP&L [Member]

Net Periodic Benefit Cost / (Income)

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended				Three months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	1.5	$	1.8	$	-	$	-
Interest cost		4.3		3.8		0.2		0.2
Expected return on plan assets (a)		(5.7)		(5.8)		(0.1)		(0.1)
Amortization of unrecognized:
Prior service cost		0.7		0.7		0.1		0.1
Actuarial loss / (gain)		1.6		2.3		(0.2)		(0.2)
Net periodic benefit cost	$	2.4	$	2.8	$	-	$	-

Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended				Nine months ended
	September 30,				September 30,
$ in millions	2014		2013		2014		2013
Service cost	$	4.4	$	5.4	$	0.1	$	0.1
Interest cost		13.0		11.6		0.6		0.6
Expected return on plan assets (a)		(17.0)		(17.6)		(0.2)		(0.2)
Amortization of unrecognized:
Prior service cost		2.1		2.1		0.1		0.1
Actuarial loss / (gain)		4.8		6.9		(0.5)		(0.5)
Net periodic benefit cost	$	7.3	$	8.4	$	0.1	$	0.1

Estimated Future Benefit Payments and Medicare Part D Reimbursements

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions	Pension		Postretirement
2014	$	6.3	$	0.5
2015		23.9		2.1
2016		23.9		2.0
2017		24.3		1.8
2018		24.6		1.6
2019 - 2023		126.5		6.7

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Supplemental Financial Information (Reclassification out of ACOI) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	$ (0.1)	$ (0.2)	$ (0.7)	$ (0.2)
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	(0.2)	(0.4)	(0.4)	(1.4)
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(1.5)	(0.8)	(7.4)	(2.1)
Reclassification of earnings of Cash Flow Hedge	(3.4)	(1.3)	(14.2)	(3.0)
Other Comprehensive Income (Loss), Net of Tax	4.4	8.1	(9.8)	22.1
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	3.6	1.7	14.6	4.7
Available-for-sale Securities [Member]
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	(0.1)	(0.2)	(0.2)	(0.7)
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.2	0.4	0.4	1.4
Other Comprehensive Income (Loss), Net of Tax			(0.2)
Total Reclassifications out of AOCI			0.4
Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	4.9	2.1	21.6	5.1
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(1.5)	(0.8)	(7.4)	(2.1)
Reclassification of earnings of Cash Flow Hedge	3.4	1.3	14.2	3.0
Other Comprehensive Income (Loss), Net of Tax			(9.6)
Total Reclassifications out of AOCI			14.2
Other Pension Plan, 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
Other Income [Member] | Available-for-sale Securities [Member]
Other Comprehensive Income (Loss) - Financial Instruments Reclassfication	0.3	0.6	0.6	2.1
Interest Expense [Member] | Derivative [Member]
Other Comprehensive Income (Loss), Net of Tax	(0.3)		(1.0)
Revenue [Member] | Derivative [Member]
Other Comprehensive Income (Loss), Net of Tax	4.9	0.5	23.4	2.2
Purchased Power [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	0.3	1.6	(0.8)	2.9
DP&L [Member]
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	(0.1)	(0.2)	(0.2)	(0.7)
Reclassification to earnings of available-for-sale securities, net of income tax expense/(benefit)	0.2	0.4	0.4	1.4
Income tax (expense)/benefit on reclassification of earnings related to derivative activity	(1.9)	(0.8)	(6.7)	(2.2)
Reclassification of earnings of Cash Flow Hedge	3.2	1.0	15.3	2.3
Other Comprehensive Income (Loss), Net of Tax			(9.1)
Other Comprehensive Income (Loss) - Pension Reclassifications	1.0	1.4	3.1	4.2
Other Comprehensive Income (Loss),Net Gain (Loss) Reclassification	0.7	0.9	2.1	2.7
Income tax (expense)/benefit on reclassification of earnings related to pension and postretirement activity	(0.3)	(0.5)	(1.0)	(1.5)
Reclassification to earnings of Pension	0.7	0.9	2.1	2.7
Total Reclassifications out of AOCI	4.1	2.3	17.8	6.4
DP&L [Member] | Available-for-sale Securities [Member]
Other Comprehensive Income (Loss), Net of Tax			(0.2)
Total Reclassifications out of AOCI			0.4
DP&L [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	5.1	1.8	22.0	4.5
Other Comprehensive Income (Loss), Net of Tax			(11.0)
Total Reclassifications out of AOCI			15.3
DP&L [Member] | Other Pension Plan, Defined Benefit [Member]
Other Comprehensive Income (Loss), Net of Tax			2.1
Total Reclassifications out of AOCI			2.1
DP&L [Member] | Other Income [Member] | Available-for-sale Securities [Member]
Other Comprehensive Income (Loss) - Financial Instruments Reclassfication	0.3	0.6	0.6	2.1
DP&L [Member] | Interest Expense [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	(0.2)	(0.6)	(0.8)	(1.8)
DP&L [Member] | Revenue [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	4.9	0.4	23.4	2.1
DP&L [Member] | Purchased Power [Member] | Derivative [Member]
Other Comprehensive Income (Loss) - Cash Flow Hedge Reclassfications	$ 0.4	$ 2.0	$ (0.6)	$ 4.2

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Common Shareholders' Equity (DP&L [Member])

9 Months Ended

Sep. 30, 2014

DP&L [Member]

Common Shareholders' Equity

10.  Shareholder’s Equity 

DP&L has 250,000,000 authorized $0.01 par value common shares, of which 41,172,173 are outstanding at September 30, 2014.  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.