8e29be99358e47c

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, 2013

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________


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

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

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

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



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

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

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


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

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



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

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


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

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

As of September 30, 2013, each registrant had the following shares of common stock outstanding:



Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, no par value	1

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

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

DPL Inc. and The Dayton Power and Light Company

Index to Quarterly Report on Form 10-Q

Quarter Ended September 30, 2013


		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	12

	Condensed Consolidated Statements of Comprehensive Income (Loss)	13

	Condensed Consolidated Statements of Cash Flows	14

	Condensed Consolidated Balance Sheets	16

	Notes to Condensed Consolidated Financial Statements	18

	The Dayton Power and Light Company

	Condensed Statements of Results of Operations	54

	Condensed Statements of Comprehensive Income (Loss)	55

	Condensed Statements of Cash Flows	56

	Condensed Balance Sheets	58

	Notes to Condensed Financial Statements	60

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	90

	Electric Sales and Revenues	121

Item 3	Quantitative and Qualitative Disclosures about Market Risk	121

Item 4	Controls and Procedures	121

DPL Inc. and The Dayton Power and Light Company

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



		Page No.
Part II Other Information

Item 1	Legal Proceedings	122

Item 1A	Risk Factors	122

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	123

Item 3	Defaults Upon Senior Securities	123

Item 4	Mine Safety Disclosures	123

Item 5	Other Information	123

Item 6	Exhibits	124

Other

Signatures		126

GLOSSARY OF TERMS

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



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

GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym	Definition
FTR	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States of America
GHG	Greenhouse Gas
kWh	Kilowatt hours
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 wholly owned subsidiary of AES, in accordance with the terms of the Merger agreement. At the Merger date, Dolphin Sub, Inc. was merged into DPL, leaving DPL as the surviving company. As a result of the Merger, DPL became a wholly owned subsidiary of AES.
Merger agreement	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
MWh	Megawatt hour
NERC	North American Electric Reliability Corporation
Non-bypassable	Charges that are assessed to all customers regardless of whom the customer selects to supply its retail electric service
NOV	Notice of Violation
NO_x	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NSR	New Source Review – a preconstruction permitting program regulating new or significantly modified sources of air pollution
NYMEX	New York Mercantile Exchange
OAQDA	Ohio Air Quality Development Authority
OCI	Other Comprehensive Income
Ohio EPA	Ohio Environmental Protection Agency
Ohio Power	Ohio Power Company, a subsidiary of American Electric Power Company, Inc. (“AEP”). Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011.
OTC	Over-The-Counter
OVEC	Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest

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

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

FORWARD-LOOKING STATEMENTS

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

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

·	unusual maintenance or repair requirements;

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

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

·	increased competition and deregulation in the electric utility industry;

·	generating unit availability and capacity;

·	transmission and distribution system reliability and capacity;

·	increased competition in the retail generation market;

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

·	changes in interest rates;

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

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

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

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

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

·	significant delays associated with large construction projects;

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

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

·	financial market conditions;

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

·	general economic conditions;

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

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

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

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

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

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

Part I – Financial Information

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

Item 1 – Financial Statements

FINANCIAL STATEMENTS

DPL INC.



DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three months ended September 30,				Nine months ended September 30,
$ in millions	2013		2012		2013		2012

Revenues	$	441.2	$	471.7	$	1,210.7	$	1,287.7

Cost of revenues:
Fuel		99.7		112.7		274.0		279.0
Purchased power		113.1		90.7		282.6		265.8
Amortization of intangibles		1.8		24.2		5.3		71.2
Total cost of revenues		214.6		227.6		561.9		616.0

Gross margin		226.6		244.1		648.8		671.7

Operating expenses:
Operation and maintenance		97.3		106.6		297.4		312.1
Depreciation and amortization		33.9		33.1		99.0		95.6
General taxes		19.4		15.7		60.8		58.7
Goodwill impairment		-		1,850.0		-		1,850.0
Total operating expenses		150.6		2,005.4		457.2		2,316.4

Operating income / (loss)		76.0		(1,761.3)		191.6		(1,644.7)

Other income / (expense), net:
Investment income		(0.5)		1.9		1.2		2.2
Interest expense		(31.0)		(31.1)		(91.1)		(93.1)
Other expense		-		(0.2)		(4.9)		(1.4)
Total other income / (expense), net		(31.5)		(29.4)		(94.8)		(92.3)

Earnings / (loss) before income taxes		44.5		(1,790.7)		96.8		(1,737.0)

Income tax expense		11.3		20.2		20.8		40.3

Net income / (loss)	$	33.2	$	(1,810.9)	$	76.0	$	(1,777.3)

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



DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

	Three months ended September 30,				Nine months ended September 30,
$ in millions	2013		2012		2013		2012

Net income / (loss)	$	33.2	$	(1,810.9)	$	76.0	$	(1,777.3)

Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $(0.1), $(0.1), $0.7 and $(0.3) for each respective period		0.2		0.2		(1.3)		0.5
Reclassification to earnings, net of income tax expense of $(0.2), $0.0, $(0.7) and $0.0 for each respective period		0.4		-		1.4		-
Total change in fair value of available-for-sale securities		0.6		0.2		0.1		0.5

Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $(3.3), $(0.3), $(10.0) and $3.4 for each respective period		6.2		0.3		18.7		(5.5)
Reclassification to earnings, net of income tax (expense) / benefit of $(0.8), $0.0, $(2.1) and $0.7 for each respective period		1.3		-		3.0		(0.8)
Total change in fair value of derivatives		7.5		0.3		21.7		(6.3)

Pension and postretirement activity:
Reclassification to earnings, net of income tax (expense) / benefit of $0.0, $0.0, $0.3 and $0.0 for each respective period		-		-		0.3		(0.1)
Total change in unfunded pension obligation		-		-		0.3		(0.1)

Other comprehensive income / (loss)		8.1		0.5		22.1		(5.9)

Net comprehensive income / (loss)	$	41.3	$	(1,810.4)	$	98.1	$	(1,783.2)

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



DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine months ended September 30,
$ in millions	2013		2012
Cash flows from operating activities:
Net income / (loss)	$	76.0	$	(1,777.3)
Adjustments to reconcile net income / (loss) to net cash from operating activities:
Depreciation and amortization		99.0		95.6
Amortization of intangibles		5.3		71.2
Amortization of debt market value adjustments		(14.3)		(14.2)
Deferred income taxes		31.5		(10.5)
Goodwill impairment		-		1,850.0
Recognition of deferred SECA revenue		-		(17.8)
Changes in certain assets and liabilities:
Accounts receivable		30.8		(10.2)
Inventories		18.6		29.5
Prepaid taxes		0.7		0.6
Taxes applicable to subsequent years		52.1		59.9
Deferred regulatory costs, net		11.6		2.7
Accounts payable		(7.2)		(16.7)
Accrued taxes payable		(69.3)		(49.4)
Accrued interest payable		24.3		25.2
Pension, retiree and other benefits		7.1		24.4
Unamortized investment tax credit		(0.4)		(0.2)
Insurance and claims costs		(2.4)		(1.3)
Other		(14.3)		(7.0)
Net cash provided by operating activities		249.1		254.5

Cash flows from investing activities:
Capital expenditures		(96.5)		(163.1)
Purchase of renewable energy credits		(3.3)		(4.8)
Decrease / (increase) in restricted cash		3.4		(0.4)
Insurance proceeds		7.6		-
Proceeds from sale of property - other		0.8		-
Other investing activities, net		(1.6)		-
Net cash used for investing activities		(89.6)		(168.3)



DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (cont.)

	Nine months ended September 30,
$ in millions	2013		2012
Net cash from financing activities:
Dividends paid on common stock to parent		-		(45.0)
Contributions to additional paid-in capital from parent		-		0.3
Payment to former warrant holders		-		(9.0)
Borrowings from revolving credit facilities		50.0		-
Repayment of borrowings from revolving credit facilities		(50.0)		-
Issuance of long-term debt, net		644.2		-
Deferred finance costs		(11.6)		(0.3)
Retirement of long-term debt		(425.1)		(0.1)
Net cash from financing activities		207.5		(54.1)

Cash and cash equivalents:
Net change		367.0		32.1
Balance at beginning of period		192.1		173.5
Cash and cash equivalents at end of period	$	559.1	$	205.6

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	79.5	$	78.1
Income taxes paid / (refunded), net	$	(20.2)	$	43.0
Non-cash financing and investing activities:
Accruals for capital expenditures	$	5.4	$	12.5

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



DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
$ in millions	2013		2012

ASSETS

Current assets:
Cash and cash equivalents	$	559.1	$	192.1
Restricted cash		7.3		10.7
Accounts receivable, net (Note 2)		180.2		208.2
Inventories (Note 2)		91.6		110.1
Taxes applicable to subsequent years		17.2		69.3
Regulatory assets, current (Note 3)		12.2		21.1
Other prepayments and current assets		45.0		43.1
Total current assets		912.6		654.6

Property, plant & equipment:
Property, plant & equipment		2,684.2		2,590.4
Less: Accumulated depreciation and amortization		(182.2)		(115.9)
		2,502.0		2,474.5
Construction work in process		52.9		89.3
Total net property, plant & equipment		2,554.9		2,563.8

Other non-current assets:
Regulatory assets, non-current (Note 3)		172.4		185.5
Goodwill		759.1		759.1
Intangible assets, net of amortization		44.1		50.1
Other deferred assets		63.0		34.2
Total other non-current assets		1,038.6		1,028.9

Total assets	$	4,506.1	$	4,247.3

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



DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
$ in millions	2013		2012

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Current portion of long-term debt (Note 5)	$	480.4	$	584.9
Accounts payable		67.9		83.2
Accrued taxes		95.8		97.1
Accrued interest		56.3		31.8
Customer security deposits		14.2		15.0
Regulatory liabilities, current (Note 3)		-		0.1
Insurance and claims costs		9.1		11.5
Other current liabilities		56.2		96.9
Total current liabilities		779.9		920.5

Non-current liabilities:
Long-term debt (Note 5)		2,334.1		2,025.0
Deferred taxes (Note 6)		576.0		534.9
Taxes payable		8.9		68.1
Regulatory liabilities, non-current (Note 3)		118.0		117.3
Pension, retiree and other benefits		63.9		61.6
Unamortized investment tax credit		2.9		3.3
Other deferred credits		73.0		71.4
Total non-current liabilities		3,176.8		2,881.6

Redeemable preferred stock of subsidiary		18.4		18.4

Commitments and contingencies (Note 10)

Common shareholders' equity:
Common stock:
1,500 shares authorized; 1 share issued and outstanding at September 30, 2013 and December 31, 2012
Other paid-in capital		2,236.9		2,236.7
Accumulated other comprehensive income / (loss)		18.2		(3.9)
Retained deficit		(1,724.1)		(1,806.0)
Total common shareholder's equity		531.0		426.8

Total liabilities and shareholder's equity	$	4,506.1	$	4,247.3

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

DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Overview and Summary of Significant Accounting Policies

Description of Business

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

DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L's SSO customers is primarily generated at eight coal-fired power plants and DP&L distributes electricity to more than 513,000 retail customers. Principal industries located in 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 and retail competition in the area. DP&L sells any excess energy and capacity into the wholesale market.

DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers. DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011. DPLER has approximately 281,000 customers currently located throughout Ohio and Illinois. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves.

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

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

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

DPL and its subsidiaries employed 1,436 people as of September 30, 2013, of which 1,376 were employed by DP&L. Approximately 53% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating facilities and numerous transmission facilities are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date for DPL. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statements of Results of Operations. See Note 4 for more information. Certain amounts in the 2012 financial statements have been reclassified to conform to the 2013 presentation.

All material intercompany accounts and transactions are eliminated in consolidation.

from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2012.

In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of September 30, 2013; our results of operations for the three and nine months ended September 30, 2013 and 2012 and our cash flows for the nine months ended September 30, 2013 and 2012. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013.

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

Goodwill Impairment

In connection with the Merger, DPL remeasured the carrying amount of all of its assets and liabilities to fair value, which resulted in the recognition of goodwill assigned to DPL’s two reporting units, DPLER and the DP&L Reporting Unit, which includes DP&L and other entities. FASC 350 “Intangibles – Goodwill and Other” requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. 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 situations, including but not limited to: deterioration in general economic conditions; changes to our operating or regulatory environment; increased competitive environment; increase in fuel costs, particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.

Sale of Receivables

In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy. These sales are at face value for cash at the amounts billed for DPLER customers’ use of energy. Total receivables sold to Duke Energy during the three months ended September 30, 2013 and 2012 were $6.1 million and $6.1 million, respectively. Total receivables sold to Duke Energy during the nine months ended September 30, 2013 and 2012 were $15.6 million and $11.3 million, respectively. Similarly, MC Squared sells receivables from their customers in ComEd territory to ComEd. Total receivables sold to ComEd during the three months ended September 30, 2013 and 2012 were $22.6 million and $0.4 million, respectively. Total receivables sold to ComEd during the nine months ended September 30, 2013 and 2012 were $57.8 million and $0.4 million, respectively. There is no recourse or any other continuing involvement associated with the sold receivables.

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 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. The total of AFUDC and capitalized interest was $0.4 million and $0.9 million for the three months ended September 30, 2013 and 2012, respectively. The total AFUDC and capitalized interest was $1.2 million and $3.4 million during the nine months ended September 30, 2013 and 2012, respectively.

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

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

Intangibles

Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. In addition, we recorded emission allowances at their fair value as of the Merger date. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. During the three and nine months ended September 30, 2013 and 2012, DPL 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 are amortized over the average length of the contracts. The value of the ESP was amortized over one year on a straight-line basis. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are amortized as they are used or retired.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DPL collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and recorded as a reduction in revenues. The amounts for the three months ended September 30, 2013 and 2012 were $13.0 million and $13.8 million, respectively. The amounts for the nine months ended September 30, 2013 and 2012 were $38.0 million and $38.5 million, respectively.

Recently Adopted Accounting Standards

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) effective for interim and annual reporting periods beginning on or after January 1, 2013. We adopted this ASU on January 1, 2013. This standard was clarified by ASU 2013-01 “Scope Clarification of Disclosures about Offsetting Assets and Liabilities”, which also was effective on January 1, 2013. This standard updates FASC Topic 210 “Balance Sheet.” ASU 2011-11 updates the disclosures for financial instruments and derivatives to provide more transparent information around the offsetting of assets and liabilities. Entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and/or subject to an agreement similar to a master netting agreement. In ASU 2013-01, the FASB clarified that the disclosures were not intended to include trade receivables and other contracts for financial instruments that may be subject to a master netting arrangement. We adopted this rule which resulted in enhanced disclosures, but did not have an effect on our overall results of operations, financial position or cash flows.

Testing Indefinite-Lived Intangible Assets for Impairments

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

Comprehensive Income

income or OCI in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the Notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. We adopted this rule which resulted in enhanced disclosures, but it did not have an effect 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, 2013 and December 31, 2012:



	September 30,		December 31,
$ in millions	2013		2012

Accounts receivable, net:
Unbilled revenue	$	58.3	$	75.2
Customer receivables		107.8		98.2
Amounts due from partners in jointly owned plants		10.2		19.7
Coal sales		-		1.6
Other		5.1		14.6
Provision for uncollectible accounts		(1.2)		(1.1)
Total accounts receivable, net	$	180.2	$	208.2

Inventories, at average cost:
Fuel and limestone	$	51.3	$	67.3
Plant materials and supplies		38.3		41.0
Other		2.0		1.8
Total inventories, at average cost	$	91.6	$	110.1

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended September 30, 2013 and 2012 are as follows:



Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended September 30,				Nine months ended September 30,
$ in millions		2013		2012		2013		2012

Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.6	$	-	$	2.1	$	-
	Total before income taxes		0.6		-		2.1		-
	Tax expense		(0.2)		-		(0.7)		-
	Net of income taxes		0.4		-		1.4		-

Gains and losses on cash flow hedges (Note 9):
	Interest Expense		-		-		-		0.2
	Revenue		0.5		0.1		2.2		(1.7)
	Purchased power		1.6		(0.1)		2.9		(0.1)
	Total before income taxes		2.1		-		5.1		(1.6)
	Tax expense		(0.8)		-		(2.1)		0.8
	Net of income taxes		1.3		-		3.0		(0.8)

Amortization of defined benefit pension items (Note 7):
	Reclassification to Other income / (deductions)		-		-		-		(0.1)
	Tax benefit		-		-		0.3		-
	Net of income taxes		-		-		0.3		-

Total reclassifications for the period, net of income taxes		$	1.7	$	-	$	4.7	$	(0.8)

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

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, 2013 are as follows:




$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges		Change in unfunded pension obligation		Total
Balance January 1, 2013	$	0.4	$	(2.5)	$	(1.8)	$	(3.9)

Other comprehensive income / (loss) before reclassifications		(1.3)		18.7		-		17.4
Amounts reclassified from accumulated other comprehensive income / (loss)		1.4		3.0		0.3		4.7
Net current period other comprehensive income		0.1		21.7		0.3		22.1

Balance September 30, 2013	$	0.5	$	19.2	$	(1.5)	$	18.2

3. Regulatory Assets and Liabilities

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

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

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

Regulatory assets and liabilities for DPL are as follows:



$ in millions	Type of Recovery ^(a)	Amortization through	September 30, 2013		December 31, 2012
Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	4.5	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		7.7		14.1
Total regulatory assets, current			$	12.2	$	21.1

Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	32.6	$	35.1
Pension benefits	C	Ongoing		84.0		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.2		11.9
Regional transmission organization costs	D	2014		1.5		2.6
Deferred storm costs	D			25.3		24.4
CCEM smart grid and AMI infrastructure costs	D			6.6		6.6
Energy Efficiency Rider costs	F	Ongoing		0.8		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.3		4.7
Total regulatory assets, non-current			$	172.4	$	185.5

Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1

Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.4	$	112.1
Postretirement benefits				4.6		5.0
Other				-		0.2
Total regulatory liabilities, non-current			$	118.0	$	117.3

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

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

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

F – Recovery of incurred costs plus rate of return.

Regulatory Assets

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

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel and purchased power recovery rider on January 1, 2010. As part of the PUCO approval process, an external auditor is hired 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. We intend to vigorously contest that disallowance. This case has been set for hearing starting December 9, 2013.

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

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

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

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

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

·	2008 – related to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other 2008 storms. On January 14, 2009, the PUCO granted DP&L the authority to defer these costs with a return until such time that DP&L seeks recovery in a future rate proceeding.

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

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

On December 21, 2012, DP&L filed a request for recovery of all of these deferred storm costs with the PUCO. This case is still pending with the PUCO. On June 17, 2013, PUCO staff recommended the disallowance of approximately $24.0 million of these costs. DP&L strongly disagrees with this recommendation and on July 3, 2013, filed a motion requesting a hearing on the issues. On October 23, 2013 the Commission issued an order directing the PUCO Staff to conduct an audit of these costs and set the hearing to begin on February 4, 2014. At September 30, 2013, DP&L believes recovery of these costs is probable.

that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. We plan to file to recover these deferred costs in a future regulatory rate proceeding. Based on PUCO precedent, we believe future recovery of these costs in rates is probable.

Energy Efficiency Rider costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency. These costs are being recovered through an energy efficiency rider that began July 1, 2009 and is subject to a two-year true-up for any over/under recovery of costs. DP&L made its most recent two-year true-up filing on April 30, 2013.

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

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

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

Regulatory Liabilities

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

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

4. Ownership of Coal-fired Facilities

DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities with certain other Ohio utilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on the energy taken. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At September 30, 2013, DP&L had $18.0 million of construction work in process at such jointly owned facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned units and stations.

DP&L’s undivided ownership interest in such facilities as well as our wholly owned coal-fired Hutchings Station at September 30, 2013 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		52		2		-	Yes
East Bend Station	31.0	186		13		4		3	Yes
Killen Station	67.0	402		305		8		2	Yes
Miami Fort Units 7 and 8	36.0	368		212		11		-	Yes
Stuart Station	35.0	808		202		12		11	Yes
Zimmer Station	28.1	365		181		22		2	Yes
Transmission (at varying percentages)		n/a		41		4		-
Total		2,465	$	1,008	$	64	$	18

Wholly owned production station:

Hutchings Station	100.0	-	$	-	$	-	$	-	No

Currently, our coal-fired generation units at Hutchings and Beckjord do not have SCR and FGD emission-control equipment installed. DP&L owns 100% of the Hutchings Station and has a 50% interest in Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at Beckjord Unit 6, filed its Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by the joint owners to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this station. Beckjord Unit 6 was valued at zero at the Merger date.

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

As part of a settlement with the USEPA, DP&L signed a Consent Agreement and Final Order (CAFO) that was filed on September 26, 2013. The CAFO resolves the opacity and particulate emissions NOV at the Hutchings Station and requires that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and includes an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013. The removal of this capacity has been reflected in the table above.

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

5. Debt Obligations

Long-term debt



$ in millions	September 30, 2013		December 31, 2012

Pollution control series maturing in January 2028 - 4.7%	$	36.0	$	36.1
Pollution control series maturing in January 2034 - 4.8%		179.6		179.6
Pollution control series maturing in September 2036 - 4.8%		96.3		96.3
Pollution control series maturing in November 2040 - rates from: 0.06% - 0.24% and 0.04% - 0.26% (a)		100.0		-
First mortgage bonds maturing in September 2016 - 1.9%		445.0		-
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligations		-		0.1
Unamortized debt discount		(0.7)		-
Total long-term debt at subsidiary		874.5		330.4

Bank term loan maturing in August 2014 (repaid in May 2013) - rates from: 2.46% and 2.22% - 2.47% (a)		-		425.0
Bank term loan maturing in May 2018 - rates from: 2.44% - 2.45% (b)		190.0		-
Senior unsecured bonds maturing in October 2016 - 6.5%		450.0		450.0
Senior unsecured bonds maturing in October 2021 - 7.3%		800.0		800.0
Note to DPL Capital Trust II maturing in September 2031 - 8.125%		19.6		19.6
Total non-current portion of long-term debt	$	2,334.1	$	2,025.0

Current portion of long-term debt



$ in millions	September 30, 2013		December 31, 2012

First mortgage bonds maturing in October 2013 - 5.125%	$	470.2	$	484.5
Pollution control series maturing in November 2040 - rates from: 0.06% - 0.24% and 0.04% - 0.26% (a)		-		100.0
Bank term loan maturing in May 2018 - rates from: 2.44% - 2.45% (b)		10.0		-
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.1		0.3
Total current portion of long-term debt	$	480.4	$	584.9

(a)Range of interest rates for the nine months ended September 30, 2013 and the twelve months ended December 31, 2012, respectively.

(b)Range of interest rates from inception of loan through September 30, 2013.

At September 30, 2013, maturities of long-term debt, including capital lease obligations, are as follows:



$ in millions due within the twelve months ending:

September 30, 2014	$	480.3
September 30, 2015		40.1
September 30, 2016		485.1
September 30, 2017		490.1
September 30, 2018		70.1
Thereafter		1,252.8
Total maturities		2,818.5

Unamortized premiums and discounts		(4.0)
Total long-term debt	$	2,814.5

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

On December 4, 2008, the OAQDA issued $100.0 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding first mortgage bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by two standby letters of credit issued by JPMorgan Chase Bank, N.A. DP&L amended these standby letters of credit on May 31, 2013 and extended the stated maturities to June 2018. These amended facilities are irrevocable, have no subjective acceleration clauses and remain subject to terms and conditions that are substantially similar to those of the pre-existing facilities. Fees associated with these standby letter of credit facilities were not material during the three and nine months ended September 30, 2013 and 2012.

On April 20, 2010, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. The agreement provided DP&L with the ability to increase the size of the facility by an additional $50.0 million. This agreement, originally for a three year term expiring on April 20, 2013, was extended through May 31, 2013 pursuant to an amendment dated April 11, 2013. DP&L had no outstanding borrowings under this credit facility at December 31, 2012 or at the termination of the agreement. Fees associated with this revolving credit facility were not material during the three and nine months ended September 30, 2013 and 2012. This facility also contained a $50.0 million letter of credit sublimit.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement was for a four year term expiring on August 24, 2015 and provided DP&L with the ability to increase the size of the facility by an additional $50.0 million. DP&L had no outstanding borrowings under this credit facility at December 31, 2012 or at the termination of the agreement. Fees associated with this revolving credit facility were not material during the three and nine months ended September 30, 2013 and 2012. This facility also contained a $50.0 million letter of credit sublimit.

On May 10, 2013, DP&L terminated both of the unsecured revolving credit agreements mentioned above and concurrently closed a new $300.0 million unsecured revolving credit agreement with a syndicated bank group. This new $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 which provides DP&L the ability to increase the size of the facility by an additional $100.0 million. The other terms and conditions of this new revolving credit facility are substantially similar to those of the pre-existing DP&L revolving credit facilities. DP&L had no outstanding borrowings under this facility at September 30, 2013. At September 30, 2013, there was a letter of credit in the amount of $0.4 million outstanding, with the remaining $299.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the three and nine months ended September 30, 2013.

DP&L’s prior unsecured revolving credit agreements and DP&L’s standby letters of credit had one financial covenant which measured 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. DP&L’s new unsecured revolving credit agreement and DP&L’s amended standby letters of credit maintain the Total Debt to Total Capitalization financial covenant and add the EBITDA to Interest Expense ratio as a second financial covenant. 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 1, 2011, DP&L completed the purchase of $18.7 million of electric transmission and distribution assets from the federal government that are located at the Wright-Patterson Air Force Base. DP&L financed the acquisition of these assets with a note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum.

On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. On October 1, 2013, DP&L used the net proceeds of these new bonds, along with cash on hand, to redeem, at par value, the $470.0 million of first mortgage bonds that matured on October 1, 2013.

On August 24, 2011, DPL entered into a $125.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement was for a three year term expiring on August 24, 2014. The size of the facility was reduced from $125.0 million to $75.0 million pursuant to an amendment dated October 19, 2012 that was negotiated between DPL and the syndicated bank group. DPL had no outstanding borrowings under this credit facility at December 31, 2012 or at the termination of the agreement on May 10, 2013. Fees associated with this revolving credit facility were not material during the three and nine months ended September 30, 2013 and 2012. This facility also had a $75.0 million letter of credit sublimit.

On May 10, 2013, DPL entered into a new $100.0 million unsecured revolving credit facility and concurrently terminated the existing $75.0 million facility. This new $100.0 million facility has a $100.0 million letter of credit sublimit and a feature which provides DPL the ability to increase the size of the facility by an additional $50.0 million. This new facility has a five year term expiring on May 10, 2018; however, if DPL has not refinanced its $450.0 million of senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this new DPL credit facility shall be July 15, 2016. The other terms and conditions of this new revolving credit facility are substantially similar to those of the pre-existing DPL revolving credit facility. On July 10, 2013, DPL repaid the $50.0 million balance that was outstanding on this credit facility as of June 30, 2013. DPL had no outstanding letters of credit under this credit facility at September 30, 2013. Fees associated with this revolving credit facility were not material during the three and nine months ended September 30, 2013.

On August 24, 2011, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group. This agreement was for a three year term expiring on August 24, 2014. At December 31, 2012 and at the termination of the agreement on May 10, 2013, as further described below, DPL had borrowed the entire $425.0 million available under this facility. Fees associated with this term loan were not material during the three and nine months ended September 30, 2013 and 2012.

On May 10, 2013, DPL entered into a new $200.0 million unsecured term loan agreement. This new term loan has a five year term expiring on May 10, 2018; however, if DPL has not either: (a) prepaid the full $200.0 million term loan balance; or (b) refinanced its $450.0 million of senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this new DPL term loan shall be July 15, 2016. This term loan amortizes at 5% of the original balance per quarter from September 2014 to maturity. The other terms and conditions of this new revolving credit facility are substantially similar to those of the pre-existing DPL term loan. Fees associated with this new term loan were not material during the three and nine months ended September 30, 2013.

Concurrent with the inception of the new revolving credit facility and term loan, DPL terminated the $425.0 million term loan agreement, and used $175.0 million of cash on hand, $50.0 million from the new DPL credit facility and $200.0 million from a one-time draw on the new term loan, to prepay the outstanding $425.0 million term loan balance. As mentioned above, the $50.0 million draw on the DPL revolving credit facility was repaid on July 10, 2013.

DPL’s prior unsecured revolving credit agreement and DPL’s prior unsecured term loan had two financial covenants, one of which was changed as part of amendments to such facilities dated October 19, 2012, negotiated between DPL and the syndicated bank groups. The first financial covenant, originally a Total Debt to Capitalization ratio, was changed, effective September 30, 2012, to a Total Debt to EBITDA ratio. The Total Debt to EBITDA ratio was 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 was an EBITDA to Interest Expense ratio. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. DPL’s new unsecured revolving credit agreement and DPL’s new unsecured term loan maintain these same two financial covenants.

DPL’s new unsecured revolving credit agreement and DPL’s new unsecured term loan executed on May 10, 2013 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 was issued in two tranches. The first tranche was $450.0 million of five year senior unsecured notes issued with a 6.50% coupon maturing on October 15, 2016. The second tranche was $800.0 million of ten year senior unsecured notes issued with a 7.25% coupon maturing on October 15, 2021.

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

6. Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,		Nine months ended September 30,
	2013	2012	2013	2012
DPL	25.4%	(1.2)%	21.5%	(2.3)%

Income tax expense for the three and nine months ended September 30, 2013 and 2012 was calculated using the estimated annual effective income tax rates for 2013 and 2012 of 31.0% and 33.2%, respectively. For the three and nine months ended September 30, 2013, management estimates the annual effective tax rate based on its forecast of annual pre-tax income. For the three and nine months ended September 30, 2012, management estimates the annual effective tax rate based on its actual pre-tax income for the period. 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, 2013, DPL’s current period effective rate is less than the estimated annual effective rate due to a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2009 tax year.

For the nine months ended September 30, 2013, DPL’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 a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years. The decrease in the effective rate compared to the same periods in 2012 is due to the factors mentioned above.

Deferred tax liabilities for DPL increased by approximately $41.1 million during the nine months ended September 30, 2013 primarily related to the resolution of the 2008 Internal Revenue Service examination in the first quarter of 2013, as well as changes in OCI and adjustments for differences between book and tax depreciation and amortization.

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

On September 13, 2013, the Internal Revenue Service released final regulations addressing the acquisition, production and improvement of tangible property and proposed regulations addressing the disposition of property. These regulations replace previously issued temporary regulations and are effective for tax years beginning on or after January 1, 2014. DPL has not yet performed a detailed analysis of the potential impact of the new regulations, but based on previously implemented method changes regarding repairs, believes it is currently in compliance with the vast majority of the provisions in the new regulations and that upon full adoption there will be no material impact on the financial statements. DPL will be evaluating elections and safe harbor methods available and future guidance yet to be issued regarding implementation of the new regulations which may change the timing of future income tax payments.

7. Pension and Postretirement Benefits

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

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. There were no contributions made during the three and nine months ended September 30, 2013 or 2012, 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, 2013 and 2012 was:



Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended September 30,				Three months ended September 30,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	-	$	-
Interest cost		3.8		4.3		0.2		0.2
Expected return on plan assets ^(a)		(5.8)		(5.7)		-		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		1.3		1.3		(0.1)		(0.1)
Prior service cost		0.3		0.4		-		-
Net periodic benefit cost before adjustments		1.4		1.8		0.1		-
Settlement cost ^(b)		-		0.2		-		-
Net periodic benefit cost	$	1.4	$	2.0	$	0.1	$	-



Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended September 30,				Nine months ended September 30,
$ in millions	2013		2012		2013		2012
Service cost	$	5.4	$	4.6	$	0.1	$	0.1
Interest cost		11.6		12.9		0.6		0.6
Expected return on plan assets ^(a)		(17.6)		(17.0)		(0.2)		(0.2)
Amortization of unrecognized:
Actuarial loss / (gain)		3.7		3.7		(0.3)		(0.5)
Prior service cost		1.1		1.1		-		-
Net periodic benefit cost before adjustments		4.2		5.3		0.2		-
Settlement cost ^(b)		-		0.2		-		-
Net periodic benefit cost	$	4.2	$	5.5	$	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 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $336.0 million, respectively.

(b) The settlement cost relates to a former officer who has elected to receive a lump sum distribution in 2012 from the Supplemental Executive Retirement Plan.



Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement

2013	$	5.5	$	0.6
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		122.6		6.8

8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The value of our financial instruments represents our best estimates of the fair value, which may not be the value realized in the future.

The following table presents the fair value and cost of our non-derivative instruments at September 30, 2013 and December 31, 2012. See also Note 9 for the fair values of our derivative instruments.



	September 30,				December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.1	$	0.1	$	0.2	$	0.2
Equity Securities		3.5		4.4		4.0		5.1
Debt Securities		5.8		5.8		4.6		5.0
Multi-Strategy Fund		-		-		0.3		0.3
Hedge Funds		0.9		0.9		-		-
Real Estate		0.4		0.4		-		-
Total Assets	$	10.7	$	11.6	$	9.1	$	10.6

Liabilities
Debt	$	2,814.5	$	2,855.3	$	2,609.9	$	2,707.1

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

Debt

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

Master Trust Assets

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

DPL had $0.7 million ($0.5 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2013 and $0.7 million ($0.5 million after tax) of unrealized gains and immaterial unrealized losses in AOCI at December 31, 2012.

During the nine months ended September 30, 2013, $2.1 million ($1.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. $0.1 million ($0.1 million after tax) of unrealized gains are expected to be reversed to earnings over the next twelve months.

Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of September 30, 2013 and December 31, 2012. These assets are part of the Master Trusts. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of September 30, 2013, DPL did not have any investments for sale at a price different from the NAV per unit.



Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at September 30, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency

Money Market Fund ^(a)	$	0.1	$	0.2	$	-	Immediate
Equity Securities ^(b)		4.4		5.1		-	Immediate
Debt Securities ^(c)		5.8		5.0		-	Immediate
Multi-Strategy Fund ^(d)		-		0.3		-	Immediate
Hedge Funds ^(e)		0.9		-		-	Immediate
Real Estate ^(f)		0.4		-		-	Immediate
Total	$	11.6	$	10.6	$	-

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

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

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

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

(e)This category includes hedge funds investing in fixed income securities and currencies, short and long-term equity investments, and a diversified fund with investments in bonds, stocks, real estate and commodities.

(f)This category includes EFT real estate funds that invest in U.S. and International properties.

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



Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2013		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		4.4		-		4.4		-
Debt Securities		5.8		-		5.8		-
Hedge Funds		0.9		-		0.9		-
Real Estate		0.4		-		0.4		-
Total Master Trust Assets		11.6		0.1		11.5		-

Derivative Assets
FTRs		0.4		-		-		0.4
Heating Oil		0.1		0.1		-		-
Forward Power Contracts		21.1		-		21.1		-
Total Derivative Assets		21.6		0.1		21.1		0.4

Total Assets	$	33.2	$	0.2	$	32.6	$	0.4

Liabilities
Derivative Liabilities
Forward Power Contracts	$	10.3	$	-	$	10.3	$	-
Total Derivative Liabilities		10.3		-		10.3		-

Long-term Debt		2,855.3		-		2,836.7		18.6

Total Liabilities	$	2,865.6	$	-	$	2,847.0	$	18.6



Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master Trust Assets
Money Market Funds	$	0.2	$	0.2	$	-	$	-
Equity Securities		5.1		-		5.1		-
Debt Securities		5.0		-		5.0		-
Multi-Strategy Fund		0.3		-		0.3		-
Total Master Trust Assets		10.6		0.2		10.4		-

Derivative Assets
Heating Oil Futures		0.2		0.2		-		-
Forward Power Contracts		6.3		-		6.3		-
Total Derivative Assets		6.5		0.2		6.3		-

Total Assets	$	17.1	$	0.4	$	16.7	$	-

Liabilities
Derivative Liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Interest Rate Hedge		29.5		-		29.5		-
Forward Power Contracts		13.1		-		13.1		-
Total Derivative Liabilities		42.7		-		42.6		0.1

Long-term debt		2,707.1		-		2,688.2		18.9

Total Liabilities	$	2,749.8	$	-	$	2,730.8	$	19.0

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

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

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

Approximately 96% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring Fair Value Measurements

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

management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. Additions to AROs were not material during the nine months ended September 30, 2013 and 2012.

Cash Equivalents

DPL had $35.0 million and $130.0 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012, respectively. The money market funds have quoted prices that are generally equivalent to par and are considered Level 1.

9. Derivative Instruments and Hedging Activities

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

At September 30, 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		10.7		-		10.7
Heating oil futures		Mark to Market	Gallons		1,638.0		-		1,638.0
Forward power contracts		Cash Flow Hedge	MWh		421.6		(4,719.4)		(4,297.8)
Forward power contracts		Mark to Market	MWh		2,653.3		(7,012.5)		(4,359.2)

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



Commodity	Accounting Treatment		Unit	Purchases (in thousands)		Sales (in thousands)		Net Purchases/ (Sales) (in thousands)
FTRs		Mark to Market	MWh		6.9		-		6.9
Heating oil futures		Mark to Market	Gallons		1,764.0		-		1,764.0
Forward power contracts		Cash Flow Hedge	MWh		1,021.0		(2,197.9)		(1,176.9)
Forward power contracts		Mark to Market	MWh		2,510.7		(4,760.4)		(2,249.7)
Interest rate swaps		Cash Flow Hedge	USD	$	160,000.0	$	-	$	160,000.0

Cash Flow Hedges

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

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

We also entered into interest rate derivative contracts to manage interest rate exposure related to anticipated 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, 2013 and 2012:



	Three months ended				Three months ended
	September 30, 2013				September 30, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(1.1)	$	12.8	$	(2.4)	$	(4.7)

Net gains / (losses) associated with current period hedging transactions		(0.2)		6.4		(2.2)		2.5

Net gains / (losses) reclassified to earnings
Revenues		0.3		-		(0.1)		-
Purchased power		1.0		-		0.1		-
Ending accumulated derivative gain / (loss) in AOCI	$	-	$	19.2	$	(4.6)	$	(2.2)

Net gains / (losses) associated with the ineffective portion of the hedging transaction are presented in the following lines of the Condensed Consolidated Statements of Results of Operations:

Interest expense	$	-	$	(0.5)	$	-	$	-

Portion expected to be reclassified to earnings in the next twelve months ^(a)	$	(2.9)	$	(1.0)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		39		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.



	Nine months ended				Nine months ended
	September 30, 2013				September 30, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(3.0)	$	0.5	$	0.3	$	(0.8)

Net gains / (losses) associated with current period hedging transactions		-		18.7		(3.8)		(1.7)

Net gains / (losses) reclassified to earnings
Interest expense		-		-		-		0.3
Revenues		1.3		-		(0.1)		-
Purchased power		1.7		-		(1.0)		-
Ending accumulated derivative gain / (loss) in AOCI	$	-	$	19.2	$	(4.6)	$	(2.2)

Net gains / (losses) associated with the ineffective portion of the hedging transaction are presented in the following lines of the Condensed Consolidated Statements of Results of Operations:

Interest expense	$	-	$	0.8	$	-	$	-

Portion expected to be reclassified to earnings in the next twelve months ^(a)	$	(2.9)	$	(1.0)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		39		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 Topic 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Consolidated Statements of Results of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. FTRs, heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts are currently marked to market.

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

Regulatory Assets and Liabilities

In accordance with regulatory accounting under GAAP, a cost 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 and the NYMEX-quality coal contracts are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed

to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.

The following tables show the amount and classification within the Condensed Consolidated Statements of Results of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2013 and 2012.



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)
Revenues	$	-	$	-	$	-	$	-
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 three months ended September 30, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total

Change in unrealized gain / (loss)	$	15.5	$	-	$	0.1	$	(2.9)	$	12.7
Realized gain / (loss)		(12.8)		0.5		0.1		0.1		(12.1)
Total	$	2.7	$	0.5	$	0.2	$	(2.8)	$	0.6

Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	4.7	$	-	$	-	$	-	$	4.7
Regulatory (asset) / liability		1.2		(0.1)		-		-		1.1

Recorded in Income Statement: gain / (loss)
Revenues		-		-		-		(2.4)		(2.4)
Purchased power		-		-		0.2		(0.4)		(0.2)
Fuel		(3.2)		0.5		-		-		(2.7)
O&M		-		0.1		-		-		0.1
Total	$	2.7	$	0.5	$	0.2	$	(2.8)	$	0.6



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 / (loss)		-		1.2		0.5		1.7
Total	$	(0.2)	$	1.6	$	11.0	$	12.4

Recorded on Balance Sheet:
Regulatory (asset) / liability	$	(0.1)	$	-	$	-	$	(0.1)

Recorded in Income Statement: gain / (loss)
Purchased power		-		1.6		11.0		12.6
Fuel		(0.1)		-		-		(0.1)
O&M		-		-		-		-
Total	$	(0.2)	$	1.6	$	11.0	$	12.4



For the nine months ended September 30, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total

Change in unrealized gain / (loss)	$	13.4	$	(1.5)	$	(0.1)	$	(0.6)	$	11.2
Realized gain / (loss)		(27.2)		1.9		0.5		(4.2)		(29.0)
Total	$	(13.8)	$	0.4	$	0.4	$	(4.8)	$	(17.8)

Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	3.5	$	-	$	-	$	-	$	3.5
Regulatory (asset) / liability		0.9		(0.6)		-		-		0.3

Recorded in Income Statement: gain / (loss)
Revenues		-		-		-		(1.7)		(1.7)
Purchased power		-		-		0.4		(3.1)		(2.7)
Fuel		(18.2)		0.8		-		-		(17.4)
O&M		-		0.2		-		-		0.2
Total	$	(13.8)	$	0.4	$	0.4	$	(4.8)	$	(17.8)

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, 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	$	1.4	$	(1.1)	$	-	$	0.3
Forward power contracts	MTM		5.1		(2.6)		-		2.5
Heating oil	MTM		0.1		-		-		0.1
FTRs	MTM		0.4		-		-		0.4

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		1.9		(0.5)		-		1.4
Forward power contracts	MTM		12.7		(0.7)		-		12.0

Total assets		$	21.6	$	(4.9)	$	-	$	16.7

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	3.7	$	(1.1)	$	(2.3)	$	0.3
Forward power contracts	MTM		5.0		(2.6)		(2.1)		0.3

Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		0.5		(0.5)		-		-
Forward power contracts	MTM		1.1		(0.7)		-		0.4

Total liabilities		$	10.3	$	(4.9)	$	(4.4)	$	1.0

At September 30, 2013, the table above includes Forward power contracts in a short-term asset position of $6.5 million and a long-term asset position of $14.6 million. Forward power contracts with a value of $2.3 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 Not Designated as Hedging Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Consolidated Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward power contracts	MTM		2.7		(1.5)		-		1.2
Heating oil futures	MTM		0.2		-		(0.2)		-

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.5		(0.5)		-		-
Forward power contracts	MTM		3.6		(0.6)		-		3.0

Total assets		$	7.5	$	(3.1)	$	(0.2)	$	4.2

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
Interest rate hedge	Cash Flow		29.5		-		-		29.5
FTRs	MTM		0.1		-		-		0.1
Forward power contracts	MTM		4.1		(1.5)		(2.0)		0.6

Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward power contracts	MTM		0.8		(0.6)		(0.1)		0.1

Total liabilities		$	42.7	$	(3.1)	$	(5.1)	$	34.5

At December 31, 2012, the table above includes Forward power contracts in a short-term asset position of $2.7 million and a long-term asset position of $3.6 million. Forward power contracts with a short-term asset position of $7.2 million and a long-term asset position of $1.0 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, 2013 was $10.3 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, 2013 were offset by $4.4 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $4.9 million. If our counterparties were to call for collateral, we could have to post collateral for the remaining $1.0 million.

10. Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. – Guarantees

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

At September 30, 2013, DPL had $18.0 million of guarantees to third parties for future financial or performance assurance under such agreements, including $17.8 million of guarantees on behalf of DPLE and DPLER 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 $0.7 million at September 30, 2013.

To date, DPL has not incurred any losses related to the guarantees of DPLE’s, DPLER’s and MC Squared’s obligations and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.

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, 2013, DP&L could be responsible for the repayment of 4.9%, or $76.9 million, of a $1,569.8 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. At September 30, 2013, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

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

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2013, cannot be reasonably determined.

Environmental Matters

The facilities and operations of DPL and its subsidiaries including DP&L are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for environmental losses that are probable of occurring and can be reasonably estimated. At September 30, 2013, we had accruals of approximately $2.2 million for environmental matters and other claims. We evaluate the potential liability related to probable losses arising from environmental matters quarterly and may revise our accruals accordingly. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial position or cash flows.

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

On July 15, 2011, Duke Energy, a co-owner at Beckjord Unit 6, filed its Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our commonly owned Unit 6, in December 2014. This was followed by a notification by the joint owners of Beckjord Unit 6 to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this station. We do not believe that any additional environmental accruals are needed as a result of this decision.

Consistent with prior disclosures, DP&L deactivated Hutchings Unit 4 on June 1, 2013. In addition, DP&L has notified PJM of its plans to deactivate the remaining Hutchings units on June 1, 2015. Depending on other factors, deactivation could occur sooner. We do not believe that any additional accruals are needed related to the Hutchings Station.

Environmental Matters Related to Air Quality

Clean Air Act Compliance

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

Clean Air Interstate Rule/Cross-State Air Pollution Rule

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

In response to the D.C. Circuit's opinion, on July 7, 2011, the USEPA issued a final rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” in these 28 states, including Ohio, which is now referred to as CSAPR. Starting in 2012, CSAPR would have required significant reductions in SO₂ and NO_x emissions from covered sources in these 28 states, such as power stations. Once fully implemented in 2014, the rule would have required additional SO₂ emission reductions of 73% and additional NO_x reductions of 54% from 2005 levels. Many states, utilities and other affected parties filed petitions for review, challenging CSAPR before the United States Court of Appeals for the D.C. Circuit. A large subset of the petitioners also sought a stay of CSAPR. On December 30, 2011, the D.C. Circuit Court granted a stay of CSAPR and directed the USEPA to continue administering CAIR. On August 21, 2012, a three-judge panel of the D.C. Circuit Court vacated CSAPR, ruling that the USEPA overstepped its regulatory authority by requiring states to make reductions beyond the levels required in the CAA and failed to provide states an initial opportunity to adopt their own measures for achieving federal compliance. As a result of this ruling, the surviving provisions of CAIR will continue to serve as the governing program until the USEPA takes further action or the U.S. Congress intervenes. Assuming that the USEPA promulgates a replacement interstate transport rule addressing the D.C. Circuit Court’s ruling, we believe companies will have three years from the date of promulgation before they would be required to comply. At this time, it is not possible to predict the details of such a replacement transport rule or what impacts it may have on our consolidated financial position, results of operations or cash flows. On October 5, 2012, the USEPA, several states and cities, as well as environmental and health organizations, filed petitions with the D.C. Circuit Court requesting a rehearing by all of the judges of the D.C. Circuit Court of the case pursuant to which the three-judge panel ruled that CSAPR be vacated. On January 24, 2013, the D.C. Circuit Court denied this petition for rehearing. Therefore, CAIR currently remains in effect. On March 19, 2013, the USEPA and several environmental groups filed two

petitions for review of the D.C. Circuit Court’s decision with the U.S. Supreme Court and on June 24, 2013, the U.S. Supreme Court granted such petitions, agreeing to review the D.C. Circuit Court’s decision. If CSAPR were to be reinstated in its current form, we would not expect any material capital costs for DP&L’s units or stations, as no uncontrolled units will be operating on coal after implementation of MATS in 2015. Because we cannot predict the final outcome of any replacement interstate transport rulemaking, we cannot currently predict its financial impact on DP&L’s operations.

Mercury and Other Hazardous Air Pollutants

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

On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities. The final rule was published in the Federal Register on March 21, 2011. This rule affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulations contain emissions limitations, operating limitations and other requirements. In December 2011, the USEPA proposed additional changes to this rule. On December 21, 2012, the Administrator of the USEPA signed the final rule and it was published in the Federal Register on January 31, 2013. DP&L expects to be in compliance with this rule and the costs are not currently expected to be material to DP&L’s operations.

National Ambient Air Quality Standards

On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. On December 31, 2012, the USEPA redesignated Adams County, where Stuart and Killen are located, to attainment status. On December 12, 2012, the USEPA tightened the PM 2.5 standard to 12.0 micrograms per cubic meter. This will begin a process of redesignations during 2014. We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial position or results of operations.

The USEPA published the national ground level ozone standard on March 12, 2008, lowering the 8 hour level from 0.08 PPM to 0.075 PPM. The USEPA finalized the area designations on April 30, 2012. DP&L cannot determine the effect of revisions to the ozone standard, if any, on its operations, however, no DP&L operations are located in non-attainment areas. The USEPA is required to review the ozone standard and is expected to propose a more stringent standard in 2014 or 2015.

Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.

Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO₂ replacing the current 24-hour standard and annual standard with a one hour standard. DP&L cannot determine the effect of this potential change, if any, on its operations.

On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. Numerous units owned and operated by us will be affected by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate GHG emissions from motor vehicles, the USEPA made a finding that CO₂ and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, the USEPA determined that CO₂ and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. On April 1, 2010, the USEPA signed the “Light-Duty Vehicle Greenhouse Gas

Emission Standards and Corporate Average Fuel Economy Standards” rule. Under the USEPA’s view, this is the final action that renders CO₂ and other GHGs “regulated air pollutants” under the CAA.

Under the USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis. Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding, its April 2010 GHG rule and the Tailoring Rule. On October 15, 2013, the U.S. Supreme Court agreed to review whether the GHG rules for motor vehicles triggered CAA permitting for stationary sources. We cannot predict the outcome of the petition. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.

On September 20, 2013, the USEPA proposed revised GHG standards for new EGUs under CAA subsection 111(b), which would require certain new EGUs to limit the amount of CO₂ emitted per megawatt-hour. The proposal anticipates that affected coal-fired units would need to rely upon partial implementation of carbon capture and storage or other expensive CO₂ emission control technology. Furthermore, the USEPA is expected to issue new standards, regulations or guidelines, as appropriate to address GHG emissions from existing EGUs. The USEPA has been directed to propose such standards by June 1, 2014 and finalize them by June 1, 2015. We cannot predict the effect of these standards, if any, on DP&L’s operations.

Approximately 97% of the energy we produce is generated by coal. DP&L’s share of CO₂emissions at generating units and 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 position. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may have on DP&L.

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

Litigation Involving Co-Owned Stations

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

As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the Stuart Station are subject to certain specified emission targets related to NO_x, SO₂ and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial position or cash flows in the future.

Notices of Violation Involving Co-Owned Stations

In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and Ohio Power (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. Although DP&L was not identified in the NOVs, civil complaints or state actions, the results of such proceedings could materially affect DP&L’s co-owned stations.

requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.

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

Notices of Violation Involving Wholly Owned Stations

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the Hutchings Station. The NOVs alleged deficiencies relate to stack opacity and particulate emissions. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L did not believe that the projects described in the November 2009 NOV were modifications subject to NSR. As part of a settlement with the USEPA, DP&L signed a Consent Agreement and Final Order (CAFO) that was filed on September 26, 2013. The CAFO resolves the opacity and particulate emissions NOV at the Hutchings Station and requires that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and includes an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013. DP&L also resolved all issues associated with the Ohio EPA NOV through a settlement signed October 4, 2013 that included the payment of an immaterial penalty.

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

Clean Water Act – Regulation of Water Intake

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

Clean Water Act – Regulation of Water Discharge

In December 2006, DP&L submitted a renewal application for the Stuart Station NPDES permit that was due to expire on June 30, 2007. The Ohio EPA issued a revised draft permit that was received on November 12, 2008. In September 2010, the USEPA formally objected to the November 12, 2008 revised permit due to questions regarding the basis for the alternate thermal limitation. At DP&L’s request, a public hearing was held on March 23, 2011 where DP&L presented its position on the issue and provided written comments. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit. In November 2012, the Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments. In December 2012, the USEPA formally withdrew its objection to the permit. On January 7, 2013, the Ohio EPA issued a final permit. On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission and a hearing has been scheduled for May 2014. Depending on the outcome of the appeals process, the effects could be material to DP&L’s operations.

the USEPA announced a proposed new rule regulating discharge of pollutants from various waste streams associated with steam EGUs. The proposal was published in the Federal Register on June 7, 2013. Following a comment period, which ended September 20, 2013, the rule is expected to be finalized by May 2014. At present, DP&L is reviewing the proposed rule and is currently unable to predict the impact this rulemaking will have on its operations.

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

In April 2012, DP&L received an NOV from the Ohio EPA related to the construction of the Carter Hollow landfill at the Stuart Station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. On September 25, 2013, a settlement with the USEPA was filed which included immaterial penalties paid in October 2013. DP&L is working with the Corps to have the permit reinstated. The landfill’s construction schedule is still uncertain.

Regulation of Waste Disposal

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

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

outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome could have a material effect on DP&L. The USEPA has indicated that the official release date for a proposed rule is projected to be sometime in July 2014.

Regulation of Ash Ponds

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

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

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

There has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule, which the USEPA has opposed. At present, the timing for a final rule regulating coal combustion byproducts cannot be determined, but the USEPA has stated possibly by 2014. If coal combustion byproducts are regulated as hazardous waste, DP&L would expect such a development to have a material adverse effect on its operations.

Notice of Violation Involving Co-Owned Units

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

Legal and Other Matters

In February 2007, DP&L filed a lawsuit in the United States District Court for the Southern District of Ohio against Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to Appalachian’s failure to supply approximately 1.5 million tons of coal to two commonly owned stations under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. Appalachian has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

11. Business Segments

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

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity sold to DP&L’s standard service offer customers is primarily generated at eight coal-fired power plants and DP&L distributes power to more than 513,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately 281,000 customers located throughout Ohio and in Illinois. This number includes 131,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier, which was acquired by DPLER in February 2011. Due to increased competition in Ohio, we have increased the number of employees and resources assigned to manage the Competitive Retail segment and increased its marketing to customers. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. The majority of intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Included 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, 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

At September 30, 2013
Total assets	$	3,837.5	$	102.8	$	565.8	$	-	$	4,506.1



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

For the three months ended September 30, 2012
Revenues from external customers	$	313.4	$	145.5	$	12.8	$	-	$	471.7
Intersegment revenues		113.4		-		0.9		(114.3)		-
Total revenues		426.8		145.5		13.7		(114.3)		471.7

Fuel		108.1		-		4.6		-		112.7
Purchased power		79.9		123.4		0.9		(113.5)		90.7
Amortization of intangibles		-		-		24.2		-		24.2

Gross margin	$	238.8	$	22.1	$	(16.0)	$	(0.8)	$	244.1

Depreciation and amortization	$	36.5	$	0.2	$	(3.6)	$	-	$	33.1
Goodwill impairment		-		-		1,850.0		-		1,850.0
Fixed asset impairment		80.8		-		-		(80.8)		-
Interest expense		10.0		0.2		21.0		(0.1)		31.1
Income tax expense (benefit)		6.5		5.9		7.8		-		20.2
Net income / (loss)		(11.2)		10.0		(1,809.7)		-		(1,810.9)

Cash capital expenditures	$	52.2	$	-	$	0.4	$	-	$	52.6

At December 31, 2012
Total assets	$	3,464.2	$	99.2	$	683.9	$	-	$	4,247.3



$ 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 September 30, 2013
Total assets	$	3,837.5	$	102.8	$	565.8	$	-	$	4,506.1



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

For the nine months ended September 30, 2012
Revenues from external customers	$	887.9	$	367.5	$	32.3	$	-	$	1,287.7
Intersegment revenues		285.1		-		2.6		(287.7)		-
Total revenues		1,173.0		367.5		34.9		(287.7)		1,287.7

Fuel		272.3		-		6.7		-		279.0
Purchased power		234.1		315.6		1.3		(285.2)		265.8
Amortization of intangibles		-		-		71.2		-		71.2

Gross margin	$	666.6	$	51.9	$	(44.3)	$	(2.5)	$	671.7

Depreciation and amortization	$	107.3	$	0.3	$	(12.0)	$	-	$	95.6
Goodwill impairment		-		-		1,850.0		-		1,850.0
Fixed asset impairment		80.8		-		-		(80.8)		-
Interest expense		29.0		0.4		64.1		(0.4)		93.1
Income tax expense (benefit)		39.4		15.8		(14.9)		-		40.3
Net income / (loss)		58.3		17.5		(1,853.1)		-		(1,777.3)

Cash capital expenditures	$	161.7	$	0.5	$	0.9	$	-	$	163.1

At December 31, 2012
Total assets	$	3,464.2	$	99.2	$	683.9	$	-	$	4,247.3

FINANCIAL STATEMENTS

The Dayton Power and Light Company



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

	Three months ended September 30,				Nine months ended September 30,
$ in millions	2013		2012		2013		2012

Revenues	$	413.1	$	426.8	$	1,141.5	$	1,173.0

Cost of revenues:
Fuel		96.7		108.1		269.6		272.3
Purchased power		110.4		79.9		276.7		234.1
Total cost of revenues		207.1		188.0		546.3		506.4

Gross margin		206.0		238.8		595.2		666.6

Operating expenses:
Operation and maintenance		87.6		103.6		270.4		298.8
Depreciation and amortization		35.8		36.5		104.5		107.3
General taxes		18.2		14.3		57.4		54.1
Fixed asset impairment		-		80.8		-		80.8
Total operating expenses		141.6		235.2		432.3		541.0

Operating income		64.4		3.6		162.9		125.6

Other income / (expense), net:
Investment income		0.1		1.9		1.7		2.1
Interest expense		(10.4)		(10.0)		(29.7)		(29.0)
Other expense		-		(0.2)		(4.3)		(1.0)
Total other income / (expense), net		(10.3)		(8.3)		(32.3)		(27.9)

Earnings / (loss) before income taxes		54.1		(4.7)		130.6		97.7
Income tax expense		13.2		6.5		29.2		39.4

Net income / (loss)		40.9		(11.2)		101.4		58.3
Dividends on preferred stock		0.2		0.2		0.6		0.6

Income / (loss) attributable to common stock	$	40.7	$	(11.4)	$	100.8	$	57.7

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



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

	Three months ended September 30,				Nine months ended September 30,
$ in millions	2013		2012		2013		2012

Net income / (loss)	$	40.9	$	(11.2)	$	101.4	$	58.3

Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $0.1, $(0.1), $0.9 and $(0.3) for each respective period		(0.2)		0.2		(1.8)		0.5
Reclassification to earnings, net of income tax expense of $(0.2), $0.0, $(0.7) and $0.0 for each respective period		0.4		-		1.4		-
Total change in fair value of available-for-sale securities		0.2		0.2		(0.4)		0.5

Derivative activity:
Change in derivative fair value, net of income tax (expense) / benefit of $0.1, $1.3, $0.0 and $2.2 for each respective period		(0.3)		(2.5)		-		(4.0)
Reclassification to earnings, net of income tax (expense) / benefit of $(0.9), $0.1, $(2.2) and $0.7 for each respective period		1.0		(0.7)		2.3		(3.1)
Total change in fair value of derivatives		0.7		(3.2)		2.3		(7.1)

Pension and postretirement activity:
Prior service cost for the period net of income tax expense of $(0.5) and $0.0, for each respective period		-		-		-		-
Reclassification to earnings, net of income tax expense of $(0.5), $(0.6), $(1.5) and $(1.7) for each respective period		0.9		1.0		2.7		3.0
Total change in unfunded pension obligation		0.9		1.0		2.7		3.0

Other comprehensive income / (loss)		1.8		(2.0)		4.6		(3.6)

Net comprehensive income / (loss)	$	42.7	$	(13.2)	$	106.0	$	54.7

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



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS

	Nine months ended September 30,
$ in millions	2013		2012
Cash flows from operating activities:
Net income	$	101.4	$	58.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		104.5		107.3
Deferred income taxes		27.1		(3.4)
Fixed asset impairment		-		80.8
Recognition of deferred SECA revenue		-		(17.8)
Changes in certain assets and liabilities:
Accounts receivable		30.7		13.0
Inventories		18.5		28.1
Prepaid taxes		0.8		0.8
Taxes applicable to subsequent years		50.0		56.2
Deferred regulatory costs, net		12.4		2.4
Accounts payable		(7.3)		(16.3)
Accrued taxes payable		(48.2)		(35.2)
Accrued interest payable		2.7		7.4
Pension, retiree and other benefits		7.1		24.4
Unamortized investment tax credit		(1.9)		(1.9)
Other		(13.9)		0.5
Net cash from operating activities		283.9		304.6

Cash flows from investing activities:
Capital expenditures		(95.1)		(161.7)
Purchase of renewable energy credits		(3.3)		(4.8)
Decrease / (increase) in restricted cash		3.4		(5.2)
Proceeds from sale of property		0.8		-
Insurance proceeds		12.1		-
Other investing activities, net		(1.7)		-
Net cash used for investing activities		(83.8)		(171.7)



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (cont.)

	Nine months ended September 30,
$ in millions	2013		2012
Net cash from financing activities:
Dividends paid on common stock to parent		(155.0)		(145.0)
Dividends paid on preferred stock		(0.6)		(0.6)
Issuance of long-term debt, net		444.2		-
Deferred finance costs		(6.7)		-
Retirement of long-term debt		(0.1)		(0.1)
Net cash from financing activities		281.8		(145.7)

Cash and cash equivalents:
Net change		481.9		(12.8)
Balance at beginning of period		28.5		32.2
Cash and cash equivalents at end of period	$	510.4	$	19.4

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	28.7	$	22.6
Income taxes paid / (refunded), net	$	(20.3)	$	30.3
Non-cash financing and investing activities:
Accruals for capital expenditures	$	5.4	$	12.5

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



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS

	September 30,		December 31,
$ in millions	2013		2012

ASSETS

Current assets:
Cash and cash equivalents	$	510.4	$	28.5
Restricted cash		7.3		10.7
Accounts receivable, net (Note 2)		132.2		160.0
Inventories (Note 2)		90.4		108.9
Taxes applicable to subsequent years		16.7		66.7
Regulatory assets, current (Note 3)		10.8		18.3
Other prepayments and current assets		37.4		33.0
Total current assets		805.2		426.1

Property, plant & equipment:
Property, plant & equipment		5,314.6		5,249.0
Less: Accumulated depreciation and amortization		(2,563.2)		(2,516.3)
		2,751.4		2,732.7
Construction work in process		50.7		87.8
Total net property, plant & equipment		2,802.1		2,820.5

Other non-current assets:
Regulatory assets, non-current (Note 3)		172.4		185.5
Intangible assets, net of amortization		8.8		9.0
Other deferred assets		49.0		23.1
Total other non-current assets		230.2		217.6

Total assets	$	3,837.5	$	3,464.2

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



THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS

	September 30,		December 31,
$ in millions	2013		2012

LIABILITIES AND SHAREHOLDER'S EQUITY

Current liabilities:
Current portion of long-term debt (Note 5)	$	470.3	$	570.4
Accounts payable		63.6		79.1
Accrued taxes		110.0		92.2
Accrued interest		15.9		13.1
Customer security deposits		33.3		35.2
Regulatory liabilities, current (Note 3)		-		0.1
Other current liabilities		50.8		52.1
Total current liabilities		743.9		842.2

Non-current liabilities:
Long-term debt (Note 5)		876.9		332.7
Deferred taxes (Note 6)		680.4		652.0
Taxes payable		8.5		66.0
Regulatory liabilities, non-current (Note 3)		118.0		117.3
Pension, retiree and other benefits		63.9		61.6
Unamortized investment tax credit		25.5		27.4
Other deferred credits		47.9		43.0
Total non-current liabilities		1,821.1		1,300.0

Redeemable preferred stock		22.9		22.9

Commitments and contingencies (Note 11)

Common shareholder's equity:
Common stock, at par value of $0.01 per share:		0.4		0.4
Other paid-in capital		803.4		803.2
Accumulated other comprehensive loss		(34.1)		(38.7)
Retained earnings		479.9		534.2
Total common shareholder's equity		1,249.6		1,299.1

Total liabilities and shareholder's equity	$	3,837.5	$	3,464.2

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

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 employed 1,376 people as of September 30, 2013. Approximately 55% of all employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in seven electric generating facilities and numerous transmission facilities which are included in the financial statements at amortized cost. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statements of Results of Operations. See Note 4 for more information. Certain amounts in the 2012 financial statements have been reclassified to conform to the 2013 presentation.

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

In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of September 30, 2013; our results of operations for the three and nine months ended September 30, 2013 and 2012 and our cash flows for the nine months ended September 30, 2013 and 2012. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2013 may not be indicative of our results that will be realized for the full year ending December 31, 2013.

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

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. The total of AFUDC and capitalized interest was $0.4 million and $0.9 million for the three months ended September 30, 2013 and 2012, respectively. The total of AFUDC and capitalized interest was $1.2 million and $3.4 million for the nine months ended September 30, 2013 and 2012, respectively.

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

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

Intangibles

Intangibles consist of emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the carrying value of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations. Renewable energy credits are amortized as they are used or retired. During the three and nine months ended September 30, 2013 and 2012, DP&L 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 are recorded as a reduction in revenues. The amounts for the three months ended September 30, 2013 and 2012 were $13.0 million and $13.8 million, respectively. The amounts for the nine months ended September 30, 2013 and 2012 were $38.0 million and $38.5 million, respectively.

Related Party Transactions

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



	Three months ended				Nine months ended
	September 30,				September 30,
$ in millions	2013		2012		2013		2012
DP&L Revenues:
Sales to DPLER ^(a)	$	93.9	$	93.3	$	254.0	$	263.7
Sales to MC Squared ^(b)	$	30.0	$	19.8	$	82.4	$	20.1

DP&L Operations and Maintenance Expenses:
Premiums paid for insurance services provided by MVIC ^(c)	$	(0.7)	$	(0.7)	$	(2.2)	$	(1.9)
Expense recoveries for services provided to DPLER ^(d)	$	1.3	$	1.2	$	3.8	$	2.7

					September 30,
DP&L Customer security deposits:					2013		2012
Deposits received from DPLER ^(e)					$	19.2	$	-

(a) DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The change in DP&L’s sales to DPLER during the three months ended September 30, 2013, compared to the three months ended September 30, 2012, is not material. The decrease in DP&L’s sales to DPLER during the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, is a result of the transfer price for the current customer base being lower than the previous year’s transfer price.

(b) DP&L also sells power to MC Squared to satisfy the electric requirements of MC Squared’s retail customers. The revenue dollars associated with sales to MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to MC Squared during the three months ended September 30, 2013, compared to the three months ended September 30, 2012, is primarily due to the significant increase of customers and the sale to MC Squared by DP&L beginning in

June 2012 and phasing in to all customers by the end of September 2012. The increase in DP&L’s sales to MC Squared during the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, is a result of the majority of these sales beginning in September 2012.

(c) 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.

(d) 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.

(e) 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 Adopted Accounting Standards

Offsetting Assets and Liabilities

Testing Indefinite-Lived Intangible Assets for Impairments

Comprehensive Income

The FASB recently issued ASU 2013-02 “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” effective for annual and interim periods beginning after December 15, 2012. This ASU does not change the current requirements for reporting net income or OCI in financial statements. However, this ASU requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the Notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. We adopted this rule which resulted in enhanced disclosures, but it did not have an effect 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, 2013 and December 31, 2012:



	September 30,		December 31,
$ in millions	2013		2012

Accounts receivable, net:
Unbilled revenue	$	33.2	$	48.1
Customer receivables		62.1		62.0
Amounts due from partners in jointly owned plants		10.2		19.7
Coal sales		-		1.6
Other		27.7		29.5
Provision for uncollectible accounts		(1.0)		(0.9)
Total accounts receivable, net	$	132.2	$	160.0

Inventories, at average cost:
Fuel and limestone	$	51.3	$	67.3
Plant materials and supplies		37.1		39.8
Other		2.0		1.8
Total inventories, at average cost	$	90.4	$	108.9

Accumulated Other Comprehensive Income / (Loss)

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



Details about Accumulated Other Comprehensive Income / (Loss) components	Affected line item in the Condensed Statements of Operations	Three months ended September 30,				Nine months ended September 30,
$ in millions		2013		2012		2013		2012

Gains and losses on Available-for-sale securities activity (Note 8):
	Other income / (deductions)	$	0.6	$	-	$	2.1	$	-
	Total before income taxes		0.6		-		2.1		-
	Tax expense		(0.2)		-		(0.7)		-
	Net of income taxes		0.4		-		1.4		-

Gains and losses on cash flow hedges (Note 9):
	Interest expense		(0.6)		(0.6)		(1.8)		(1.8)
	Revenue		0.4		(0.2)		2.1		(2.2)
	Purchased power		2.0		-		4.2		0.2
	Total before income taxes		1.8		(0.8)		4.5		(3.8)
	Tax expense		(0.8)		0.1		(2.2)		0.7
	Net of income taxes		1.0		(0.7)		2.3		(3.1)

Amortization of defined benefit pension items (Note 7):
	Reclassification to Other income / (deductions)		1.4		1.6		4.2		4.6
	Tax benefit		(0.5)		(0.6)		(1.5)		(1.6)
	Net of income taxes		0.9		1.0		2.7		3.0

Total reclassifications for the period, net of income taxes		$	2.3	$	0.3	$	6.4	$	(0.1)

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the nine months ended September 30, 2013 are as follows:




$ in millions	Gains / (losses) on available-for-sale securities		Gains / (losses) on cash flow hedges		Change in unfunded pension obligation		Total
Balance January 1, 2013	$	1.0	$	2.6	$	(42.3)	$	(38.7)

Other comprehensive income / (loss) before reclassifications		(1.8)		-		-		(1.8)
Amounts reclassified from accumulated other comprehensive income / (loss)		1.4		2.3		2.7		6.4
Net current period other comprehensive income / (loss)		(0.4)		2.3		2.7		4.6

Balance September 30, 2013	$	0.6	$	4.9	$	(39.6)	$	(34.1)

3. Regulatory Assets and Liabilities

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

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

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

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



$ in millions	Type of Recovery ^(a)	Amortization through	At September 30, 2013		At December 31, 2012

Regulatory assets, current:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	4.5	$	7.0
Fuel and purchased power recovery costs	C	Ongoing		6.3		11.3
Total regulatory assets, current			$	10.8	$	18.3

Regulatory assets, non-current:
Deferred recoverable income taxes	B/C	Ongoing	$	32.6	$	35.1
Pension benefits	C	Ongoing		84.0		88.9
Unamortized loss on reacquired debt	C	Ongoing		11.2		11.9
Regional transmission organization costs	D	2014		1.5		2.6
Deferred storm costs	D			25.3		24.4
CCEM smart grid and AMI infrastructure costs	D			6.6		6.6
Energy Efficiency Rider costs	F	Ongoing		0.8		5.2
Consumer education campaign	D			3.0		3.0
Retail settlement system costs	D			3.1		3.1
Other costs				4.3		4.7
Total regulatory assets, non-current			$	172.4	$	185.5

Regulatory liabilities, current:
Other			$	-	$	0.1
Total regulatory liabilities, current			$	-	$	0.1

Regulatory liabilities, non-current:
Estimated costs of removal - regulated property			$	113.4	$	112.1
Postretirement benefits				4.6		5.0
Other				-		0.2
Total regulatory liabilities, non-current			$	118.0	$	117.3

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

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

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

F – Recovery of incurred costs plus rate of return.

Regulatory Assets

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

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

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

·	2008 – related to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other 2008 storms. On January 14, 2009, the PUCO granted DP&L the authority to defer these costs with a return until such time that DP&L seeks recovery in a future rate proceeding.

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

On December 21, 2012, DP&L filed a request for recovery of all of these deferred storm costs with the PUCO. On June 17, 2013, PUCO staff recommended the disallowance of approximately $24.0 million of these costs. DP&L strongly disagrees with this recommendation and filed a motion requesting a hearing on the issues. On October 23, 2013 the Commission issued an order directing the PUCO Staff to conduct an audit of these costs and set the hearing to begin on February 4, 2014. At September 30, 2013, DP&L believes recovery of these costs is probable.

CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. We plan to file to recover these deferred costs in a future regulatory rate proceeding. Based on PUCO precedent, we believe future recovery of these costs in rates is probable.

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

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

Regulatory Liabilities

4. Ownership of Coal-fired Facilities

DP&L has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities with certain other Ohio utilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on the energy taken. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of September 30, 2013, DP&L had $18.0 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 as well as our wholly owned coal-fired Hutchings Station at September 30, 2013, 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	$	67	$	-	No
Conesville Unit 4	16.5	129		44		1		-	Yes
East Bend Station	31.0	186		210		139		3	Yes
Killen Station	67.0	402		624		303		2	Yes
Miami Fort Units 7 and 8	36.0	368		361		149		-	Yes
Stuart Station	35.0	808		744		305		11	Yes
Zimmer Station	28.1	365		1,098		652		2	Yes
Transmission (at varying percentages)				97		60		-
Total		2,465	$	3,254	$	1,676	$	18

Wholly owned production station:

Hutchings Station	100.0	-	$	-	$	-	$	-	No

Currently, our coal-fired generation units at Hutchings and Beckjord do not have SCR and FGD emission-control equipment installed. DP&L owns 100% of the Hutchings Station and has a 50% interest in Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed its Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by the joint owners to PJM, dated April 12, 2012, of a planned June 1, 2015 deactivation of this unit.

As part of a settlement with the USEPA, DP&L signed a Consent Agreement and Final Order (CAFO) that was filed on September 26, 2013. The CAFO resolves the opacity and particulate emissions NOV at the Hutchings Station and requires that all six coal-fired units at Hutchings cease operating on coal by September 30, 2013, and include an immaterial penalty and the completion of a Supplemental Environmental Project of $0.2 million within one year. The units were disabled for coal operations prior to September 30, 2013. The removal of this capacity has been reflected in the table above.

5. Debt Obligations

Long-term debt



$ in millions	September 30, 2013		December 31, 2012

Pollution control series maturing in January 2028 - 4.7%	$	35.3	$	35.3
Pollution control series maturing in January 2034 - 4.8%		179.1		179.1
Pollution control series maturing in September 2036 - 4.8%		100.0		100.0
Pollution control series maturing in November 2040 - rates from: 0.06% - 0.24% and 0.04% - 0.26% (a)		100.0		-
First mortgage bonds maturing in September 2016 - 1.875%		445.0		-
U.S. Government note maturing in February 2061 - 4.2%		18.3		18.3
Capital lease obligation		-		0.1
Unamortized debt discount		(0.8)		(0.1)
Total non-current portion of long-term debt	$	876.9	$	332.7

Current portion of long-term debt



$ in millions	September 30, 2013		December 31, 2012

First mortgage bonds maturing in October 2013 - 5.125%	$	470.0	$	470.0
Pollution control series maturing in November 2040 - rates from: 0.06% - 0.24% and 0.04% - 0.26% (a)		-		100.0
U.S. Government note maturing in February 2061 - 4.2%		0.1		0.1
Capital lease obligations		0.2		0.3
Total current portion of long-term debt	$	470.3	$	570.4

(a) Range of interest rates for the nine months ended September 30, 2013 and the twelve months ended December 31, 2012, respectively.

At September 30, 2013, maturities of long-term debt, including capital lease obligations, are as follows:



$ in millions due within the twelve months ending:

September 30, 2014	$	470.3
September 30, 2015		0.1
September 30, 2016		445.1
September 30, 2017		0.1
September 30, 2018		0.1
Thereafter		431.5
Total long-term debt	$	1,347.2

DP&L’s unsecured revolving credit agreements and DP&L’s standby letter of credit had one financial covenant which measured 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. DP&L’s new unsecured revolving credit agreement and DP&L’s amended standby letters of credit maintain the Total Debt to Total Capitalization financial covenant and add the EBITDA to Interest Expense ratio as a second financial covenant. 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.

6. Income Taxes

The following table details the effective tax rates for the three and nine months ended September 30, 2013 and 2012.



	Three months ended September 30,		Nine months ended September 30,
	2013	2012	2013	2012
DP&L	24.4%	(138.3)%	22.5%	40.3%

Income tax expense for the three and nine months ended September 30, 2013 and 2012 was calculated using the estimated annual effective income tax rates for 2013 and 2012 of 29.5% and 30.7%, respectively. For the three and nine months ended September 30, 2013, management estimates the annual effective tax rate based on its forecast of annual pre-tax income. For the three and nine months ended September 30, 2012, management estimates the annual effective tax rate based on its actual pre-tax income for the period. 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, 2013, DP&L’s current period effective rate is less than the estimated annual effective rate due to a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2009 tax year.

For the nine months ended September 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 deferred tax adjustment related to the expiration of the statute of limitations on the 2007, 2008 and 2009 tax years. The decrease in the effective rate compared to the same periods in 2012 is due to the factors mentioned above.

Deferred tax liabilities for DP&L increased by approximately $28.4 million during the nine months ended September 30, 2013 primarily related to the resolution of the 2008 Internal Revenue Service examination in the first quarter of 2013, as well as changes in OCI and adjustments for differences between book and tax depreciation and amortization.

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

On September 13, 2013, the Internal Revenue Service released final regulations addressing the acquisition, production and improvement of tangible property and proposed regulations addressing the disposition of property. These regulations replace previously issued temporary regulations and are effective for tax years beginning on or after January 1, 2014. DP&L has not yet performed a detailed analysis of the potential impact of the new regulations, but based on previously implemented method changes regarding repairs, believes it is currently in compliance with the vast majority of the provisions in the new regulations and that upon full adoption there will be no material impact on the financial statements. DP&L will be evaluating elections and safe harbor methods available and future guidance yet to be issued regarding implementation of the new regulations which may change the timing of future income tax payments.

7. Pension and Postretirement Benefits

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

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 ended September 30, 2013 and 2012 was:



Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Three months ended September 30,				Three months ended September 30,
$ in millions	2013		2012		2013		2012
Service cost	$	1.8	$	1.5	$	-	$	-
Interest cost		3.8		4.3		0.2		0.2
Expected return on plan assets ^(a)		(5.8)		(5.7)		(0.1)		(0.1)
Amortization of unrecognized:
Actuarial loss / (gain)		2.3		2.4		(0.2)		(0.2)
Prior service cost		0.7		0.7		0.1		0.1
Net periodic benefit cost before adjustments		2.8		3.2		-		-
Settlement cost ^(b)		-		0.5		-		-
Net periodic benefit cost	$	2.8	$	3.7	$	-	$	-



Net Periodic Benefit Cost / (Income)	Pension				Postretirement
	Nine months ended September 30,				Nine months ended September 30,
$ in millions	2013		2012		2013		2012
Service cost	$	5.4	$	4.6	$	0.1	$	0.1
Interest cost		11.6		12.9		0.6		0.6
Expected return on plan assets ^(a)		(17.6)		(17.0)		(0.2)		(0.2)
Amortization of unrecognized:
Actuarial loss / (gain)		6.9		7.1		(0.5)		(0.7)
Prior service cost		2.1		2.2		0.1		0.1
Net periodic benefit cost / (income) before adjustments		8.4		9.8		0.1		(0.1)
Settlement cost ^(b)		-		0.5		-		-
Net periodic benefit cost / (income)	$	8.4	$	10.3	$	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 three and nine months ended September 30, 2013 and 2012 net periodic benefit cost was approximately $346.0 million and $335.0 million, respectively.

(b) The settlement cost relates to a former officer who has elected to receive a lump sum distribution in 2012 from the Supplemental Executive Retirement Plan.



Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:

$ in millions	Pension		Postretirement

2013	$	5.5	$	0.6
2014		22.5		2.2
2015		23.0		2.0
2016		23.3		1.9
2017		23.7		1.7
2018 - 2022		122.6		6.8

8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The value of our financial instruments represents our best estimates of fair value, which may not be the value realized in the future. The following table presents the fair value and cost of our non-derivative instruments at September 30, 2013 and December 31, 2012. See also Note 9 for the fair values of our derivative instruments.



	September 30,				December 31,
	2013				2012
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money market funds	$	0.1	$	0.1	$	0.2	$	0.2
Equity securities		3.5		4.4		4.0		5.1
Debt securities		5.8		5.8		4.6		5.0
Multi-strategy fund		-		-		0.3		0.3
Hedge funds		0.9		0.9		-		-
Real estate		0.4		0.4		-		-
Total assets	$	10.7	$	11.6	$	9.1	$	10.6

Liabilities
Debt	$	1,347.2	$	1,330.8	$	903.1	$	926.9

Debt

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

Master Trust Assets

DP&L established 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.

DP&L had $1.0 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2013 and $1.6 million ($1.0 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2012.

Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of September 30, 2013. These assets are part of the Master Trusts. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. At September 30, 2013, DP&L did not have any investments for sale at a price different from the NAV per unit.



Fair Value Estimated Using Net Asset Value per Unit
$ in millions	Fair Value at September 30, 2013		Fair Value at December 31, 2012		Unfunded Commitments		Redemption Frequency

Money market fund ^(a)	$	0.1	$	0.2	$	-	Immediate
Equity securities ^(b)		4.4		5.1		-	Immediate
Debt securities ^(c)		5.8		5.0		-	Immediate
Multi-strategy fund ^(d)		-		0.3		-	Immediate
Hedge funds ^(e)		0.9		-		-	Immediate
Real estate ^(f)		0.4		-		-	Immediate
Total	$	11.6	$	10.6	$	-

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

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

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

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

(f)This category includes EFT real estate funds that invest in U.S. and International properties.

Fair Value Hierarchy



Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at September 30, 2013		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		4.4		-		4.4		-
Debt securities		5.8		-		5.8		-
Hedge funds		0.9		-		0.9		-
Real estate		0.4		-		0.4		-
Total Master trust assets		11.6		0.1		11.5		-

Derivative assets
FTRs		0.4		-		-		0.4
Heating Oil		0.1		0.1		-		-
Forward power contracts		21.2		-		21.2		-
Total derivative assets		21.7		0.1		21.2		0.4

Total assets	$	33.3	$	0.2	$	32.7	$	0.4

Liabilities
Derivative liabilities
Forward power contracts		10.1		-		10.1		-
Total derivative liabilities		10.1		-		10.1		-

Long-term debt		1,330.8		-		1,312.2		18.6

Total liabilities	$	1,340.9	$	-	$	1,322.3	$	18.6



Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at December 31, 2012		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs
Assets
Master trust assets
Money market funds	$	0.2	$	0.2	$	-	$	-
Equity securities		5.1		-		5.1		-
Debt securities		5.0		-		5.0		-
Multi-strategy fund		0.3		-		0.3		-
Total Master trust assets		10.6		0.2		10.4		-

Derivative assets
Heating oil futures		0.2		0.2		-		-
Forward power contracts		7.3		-		7.3		-
Total Derivative assets		7.5		0.2		7.3		-

Total assets	$	18.1	$	0.4	$	17.7	$	-

Liabilities
Derivative liabilities
FTRs	$	0.1	$	-	$	-	$	0.1
Forward power contracts		11.6		-		11.6		-
Total Derivative liabilities		11.7		-		11.6		0.1

Long-term debt		926.9		-		908.0		18.9

Total liabilities	$	938.6	$	-	$	919.6	$	19.0

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

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

Approximately 96% of the inputs to the fair value of our derivative instruments are from quoted market prices for DP&L.

Non-recurring Fair Value Measurements

management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. Additions to AROs were not material during the three and nine months ended September 30, 2013 and 2012.

9. Derivative Instruments and Hedging Activities

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

At September 30, 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		10.7		-		10.7
Heating oil futures		Mark to Market	Gallons		1,638.0		-		1,638.0
Forward power contracts		Cash Flow Hedge	MWh		421.6		(4,719.4)		(4,297.8)
Forward power contracts		Mark to Market	MWh		2,624.6		(7,041.3)		(4,416.7)

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



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

Cash Flow Hedges

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 ended September 30, 2013 and 2012:



	Three months ended				Three months ended
	September 30, 2013				September 30, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(1.9)	$	6.1	$	(3.4)	$	8.6

Net gains / (losses) associated with current period hedging transactions		(0.3)		-		(2.5)		(0.6)

Net gains / (losses) reclassified to earnings
Interest expense		-		(0.6)		-		-
Revenues		0.3		-		-		-
Purchased power		1.3		-		(0.1)		-
Ending accumulated derivative gain / (loss) in AOCI	$	(0.6)	$	5.5	$	(6.0)	$	8.0

Portion expected to be reclassified to earnings in the next twelve months ^(a)	$	(2.3)	$	(2.4)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		39		-

(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.



	Nine months ended				Nine months ended
	September 30, 2013				September 30, 2012
			Interest				Interest
$ in millions (net of tax)	Power		Rate Hedge		Power		Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(4.7)	$	7.3	$	(0.7)	$	9.8

Net gains / (losses) associated with current period hedging transactions		-		-		(4.0)		-

Net gains / (losses) reclassified to earnings
Interest expense		-		(1.8)		-		(1.8)
Revenues		1.4		-		0.1		-
Purchased power		2.7		-		(1.4)		-
Ending accumulated derivative gain / (loss) in AOCI	$	(0.6)	$	5.5	$	(6.0)	$	8.0

Portion expected to be reclassified to earnings in the next twelve months ^(a)	$	(2.3)	$	(2.4)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)		39		-

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

Mark to Market Accounting

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

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting and are recognized in the statements of results of operations on an accrual basis.

Regulatory Assets and Liabilities

The following tables show the amount and classification within the statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2013 and 2012:



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 three months ended September 30, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total

Change in unrealized gain / (loss)	$	15.5	$	-	$	0.1	$	(5.5)	$	10.1
Realized gain / (loss)		(12.8)		0.5		0.1		4.2		(8.0)
Total	$	2.7	$	0.5	$	0.2	$	(1.3)	$	2.1

Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	4.7	$	-	$	-	$	-	$	4.7
Regulatory (asset) / liability		1.2		(0.1)		-		-		1.1

Recorded in Income Statement: gain / (loss)
Revenues		-		-		-		0.3		0.3
Purchased power		-		-		0.2		(1.6)		(1.4)
Fuel		(3.2)		0.5		-		-		(2.7)
O&M		-		0.1		-		-		0.1
Total	$	2.7	$	0.5	$	0.2	$	(1.3)	$	2.1



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 / (loss)		-		1.2		1.1		2.3
Total	$	(0.2)	$	1.6	$	10.0	$	11.4

Recorded on Balance Sheet:
Regulatory (asset) / liability	$	(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)
O&M		-		-		-		-
Total	$	(0.2)	$	1.6	$	10.0	$	11.4



For the nine months ended September 30, 2012
	NYMEX
$ in millions	Coal		Heating Oil		FTRs		Power		Total

Change in unrealized gain / (loss)	$	13.4	$	(1.5)	$	(0.1)	$	(4.6)	$	7.2
Realized gain / (loss)		(27.2)		1.9		0.5		4.2		(20.6)
Total	$	(13.8)	$	0.4	$	0.4	$	(0.4)	$	(13.4)

Recorded on Balance Sheet:
Partners' share of gain / (loss)	$	3.5	$	-	$	-	$	-	$	3.5
Regulatory (asset) / liability		0.9		(0.6)		-		-		0.3

Recorded in Income Statement: gain / (loss)
Revenues		-		-		-		2.0		2.0
Purchased power		-		-		0.4		(2.4)		(2.0)
Fuel		(18.2)		0.8		-		-		(17.4)
O&M		-		0.2		-		-		0.2
Total	$	(13.8)	$	0.4	$	0.4	$	(0.4)	$	(13.4)

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. The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments at September 30, 2013:



Fair Values of Derivative Instruments
at September 30, 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	$	1.4	$	(1.1)	$	-	$	0.3
Forward power contracts	MTM		5.2		(2.6)		-		2.6
Heating oil futures	MTM		0.1		-		-		0.1
FTRs	MTM		0.4		-		-		0.4

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		1.9		(0.5)		-		1.4
Forward power contracts	MTM		12.7		(0.7)		-		12.0

Total assets		$	21.7	$	(4.9)	$	-	$	16.8

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	3.8	$	(1.1)	$	(2.3)	$	0.4
Forward power contracts	MTM		4.7		(2.6)		(1.8)		0.3

Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		0.5		(0.5)		-		-
Forward power contracts	MTM		1.1		(0.7)		(0.1)		0.3

Total liabilities		$	10.1	$	(4.9)	$	(4.2)	$	1.0

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



Fair Values of Derivative Instruments
at December 31, 2012
				Gross Amounts Not Offset in the Condensed Balance Sheets
$ in millions	Hedging Designation	Gross Fair Value as presented in the Condensed Balance Sheets		Financial Instruments with Same Counterparty in Offsetting Position		Cash Collateral		Net Amount
Assets
Short-term derivative positions (presented in Other current assets)
Forward power contracts	Cash Flow	$	0.5	$	(0.5)	$	-	$	-
Forward power contracts	MTM		2.8		(1.5)		-		1.3
Heating oil futures	MTM		0.2		-		(0.2)		-

Long-term derivative positions (presented in Other deferred assets)
Forward power contracts	Cash Flow		0.5		(0.5)		-		-
Forward power contracts	MTM		3.6		(0.6)		-		3.0

Total assets		$	7.6	$	(3.1)	$	(0.2)	$	4.3

Liabilities
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts	Cash Flow	$	6.7	$	(0.5)	$	(2.1)	$	4.1
FTRs	MTM		0.1		-		-		0.1
Forward power contracts	MTM		2.7		(1.5)		(0.5)		0.7

Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts	Cash Flow		1.5		(0.5)		(0.9)		0.1
Forward power contracts	MTM		0.7		(0.6)		-		0.1

Total liabilities		$	11.7	$	(3.1)	$	(3.5)	$	5.1

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, 2013 was $10.1 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, 2013 were offset by $4.2 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $4.9 million. If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $1.0 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, 2013. All common shares are held by DP&L’s parent, DPL.

On August 5, 2013, the Board of Directors of DP&L declared a dividend to the common stockholder of record as of the close of business on August 6, 2013 of up to $75.0 million during the third quarter of 2013; $25.0 million was paid by September 30, 2013, the remainder will not be paid.

On November 5, 2013, the Board of Directors of DP&L declared a dividend to the common stockholder of record as of the close of business on November 6, 2013 of up to $75.0 million payable during the fourth quarter of 2013.

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

11. Contractual Obligations, Commercial Commitments and Contingencies

DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP. As of September 30, 2013, DP&L could be responsible for the repayment of 4.9%, or $76.9 million, of a $1,569.8 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, 2013, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

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, 2013, cannot be reasonably determined.

Environmental Matters

The facilities and operations of DP&L are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for environmental losses that are probable of occurring and can be reasonably estimated. At September 30, 2013, we had accruals of approximately $2.2 million for environmental matters and other claims. We evaluate the potential liability related to probable losses arising from environmental matters quarterly and may revise our accruals accordingly. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial position or cash flows.

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

Environmental Matters Related to Air Quality

Clean Air Act Compliance

Clean Air Interstate Rule/Cross-State Air Pollution Rule

Mercury and Other Hazardous Air Pollutants

was finalized on March 28, 2013. Our affected EGUs will have to come into compliance with MATS by April 16, 2015. DP&L is evaluating the costs that may be incurred to comply with MATS; however, MATS could have a material adverse effect on our operations and result in material costs.

National Ambient Air Quality Standards

Carbon Dioxide and Other Greenhouse Gas Emissions

vehicles triggered CAA permitting for stationary sources. We cannot predict the outcome of the petition. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.

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

Litigation Involving Co-Owned Stations

Notices of Violation Involving Co-Owned Stations

In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart Station (co-owned by DP&L, Duke Energy and Ohio Power) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest, including the NOVs noted in the paragraph above. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.

Notices of Violation Involving Wholly Owned Stations

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

Clean Water Act – Regulation of Water Intake

Clean Water Act – Regulation of Water Discharge

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. On April 19, 2013, the USEPA announced a proposed new rule regulating discharge of pollutants from various waste streams associated with steam EGUs. The proposal was published in the Federal Register on June 7, 2013. Following a comment period which ended September 20, 2013, the rule is expected to be finalized by May 2014. At present, DP&L is reviewing the proposed rule and is currently unable to predict the impact this rulemaking will have on its operations.

creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. On September 25, 2013, a settlement with the USEPA was filed which included immaterial penalties paid in October 2013. DP&L is working with the Corps to have the permit reinstated. The landfill’s construction schedule is still uncertain.

Regulation of Waste Disposal

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

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

Regulation of Ash Ponds

There has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. Litigation has been filed by several groups seeking a court-ordered deadline for the issuance of a final rule which the USEPA has opposed. At present, the timing for a final rule regulating coal combustion byproducts cannot be determined, but the USEPA has stated possibly by 2014. If coal combustion byproducts are regulated as hazardous waste, DP&L would expect such a development to have a material adverse effect on its operations.

Notice of Violation Involving Co-Owned Units

Legal and Other Matters

In February 2007, DP&L filed a lawsuit in the United States District Court for the Southern District of Ohio against Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to Appalachian’s failure to supply approximately 1.5 million tons of coal to two commonly owned stations under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. The supplier has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

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

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

DESCRIPTION OF BUSINESS

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 11 of Notes to DPL’s Condensed Consolidated Financial Statements for more information relating to these reportable segments.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity sold to DP&L's SSO customers is primarily generated at eight coal-fired power plants. DP&L distributes electricity to more than 513,000 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, which was purchased on February 28, 2011. DPLER has approximately 281,000 customers currently located throughout Ohio and Illinois. Approximately 42% 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 or PJM to meet its sales obligations.

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

DPL and its subsidiaries employed 1,436 people as of September 30, 2013, of which 1,376 employees were employed by DP&L. Approximately 53% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2014.

REGULATORY ENVIRONMENT

DPL’s, DP&L’s and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and

remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated.

NO_x and SO₂Emissions – CAIR and CSAPR

Carbon Dioxide and Other Greenhouse Gas Emissions

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

Various industry groups and states petitioned the U.S. Supreme Court to review the D.C. Circuit Court’s recent decision to uphold the USEPA’s endangerment finding and certain GHG regulations based on that endangerment finding. On October 15, 2013, the U.S. Supreme Court agreed to review whether the USEPA’s regulation of GHGs from motor vehicles triggered CAA permitting for stationary sources. As a result of the endangerment finding and other USEPA regulations, emissions of CO₂ and other GHGs from certain EGUs and other stationary sources are subject to regulation. Increased pressure for GHG emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Approximately 97% of the energy we produce is generated by coal. DP&L’s share of CO₂emissions at generating stations we own and co-own is approximately 14 million tons annually. If we are

required to implement control of CO₂ and other GHGs at generation facilities, the cost to DPL and DP&L of such reductions could be material.

Clean Water Act

Climate Change Legislation and Regulation

On June 25, 2013, the President of the United States directed the USEPA to issue a new proposed rule establishing New Source Performance Standards for carbon dioxide (“CO₂”) emissions for newly constructed fossil-fueled EGUs larger than 25 MW by September 2013, and to issue a final rule in a timely fashion after considering all public comments. The EPA issued such new proposed rule in September 2013. The proposed rule anticipates that newly constructed fossil-fueled power plants generally would need to rely upon partial implementation of carbon capture and storage technology or other pollution control technology to meet the standard.

In his June 25, 2013 announcement, the President, as anticipated, also directed the USEPA to issue new standards, regulations, or guidelines, as appropriate, that address CO₂ emissions from existing power plants. The President directed the USEPA to (i) issue a proposed rule by June 1, 2014; (ii) issue a final rule by June 1, 2015; and (iii) require that States submit their implementation plans to the USEPA by no later than June 30, 2016. Following this announcement, in September 2013, 18 states, including Indiana, sent the USEPA a white paper questioning the USEPA’s legal authority to impose CO₂emission standards on existing power plants. It is too soon to determine whether any such standards would materially impact DP&L’s operations.

It is impossible to estimate the impact and compliance costs associated with any future USEPA GHG regulations applicable to new, modified or existing EGUs until such regulations are finalized; however, the impact, including the compliance costs, could be material to our consolidated financial condition or results of operations.

Electric Security Plan

SB 221 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 “significantly excessive earnings test” (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. The plan was refiled on December 12, 2012 to correct for certain projected costs. The plan requested approval of a non-bypassable charge, designed to recover $137.5 million per year for five years from all customers. The ESP stated that DP&L intends to file on or before December 31, 2013 its plan for legal separation of its generation assets. The ESP proposed a three year, five month transition to market, whereby a wholesale competitive bidding structure will be phased in to supply generation service to customers located in DP&L’s service territory that have not chosen an alternative generation supplier. An evidentiary hearing on this case was held March 18, 2013 through April 3, 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).

The ESP Order stated that DP&L’s next ESP begins January 2014 and extends through May 31, 2017. DP&L’s current rate structure remains in place until January 1, 2014. The PUCO authorized DP&L to collect a nonbypassable Service Stability Rider (SSR) equal to $110.0 million per year for 2014 – 2016. DP&L has the opportunity to seek an additional $45.8 million through extension of the SSR provided the Company meets certain regulatory filing obligations, which include, but are not limited to, filing a plan by December 31, 2013 to separate the generation assets from the utility and file a distribution rate case no later than July 1, 2014. The

ESP Order also directs DP&L to divest its generation assets no later than May 31, 2017, and sets DP&L’s SEET threshold at a 12% ROE. The ESP Order 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, 40% in 2015, 70% in 2016 and 100% in 2017. The ESP Order approved DP&L’s rate proposal to bifurcate its transmission charges into a non-bypassable component and a bypassable component. The ESP order also denied DP&L’s request to seek a nonbypassable charge to recover the cost of its Yankee Solar facility and required the Company to establish a $2 million per year shareholder funded economic development fund. Applications for rehearing were filed on October 4, 2013 by DP&L and other parties and are currently pending Commission action. On October 23, 2013 the Commission issued an entry on rehearing denying applications for rehearing that related to the competitive bid. The Commission reaffirmed its position that economic development load should be included in the competitive bid auction and that DP&L’s affiliates are permitted to bid in the auction.

Through its ESP order, DP&L was directed by the PUCO to conduct a competitive bid auction no later than November 1, 2013 to solicit wholesale generation supply for 10% of its standard service offer load. DP&L held the auction on Monday, October 28. The auction resulted in a market-based price of $49.32 per MWH. This price will be blended into DP&L’s existing rates and assessed for all standard service offer load beginning January 1, 2014.

SB 221 Renewable and Energy Efficiency Requirements

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. The standards require that, by the year 2025, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including 0.5% from solar energy. The renewable energy portfolio, energy efficiency and demand reduction standards began in 2009 with increased percentage requirements each year thereafter. Energy efficiency programs are expected to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to a baseline energy usage. If any targets are not met, compliance penalties will apply, unless the PUCO makes certain findings that would excuse performance.

Ohio HB 58 was introduced by Senator Seitz in September 2013. As proposed the bill would lower future energy efficiency targets and allow for less stringent standards for counting energy efficiency savings towards the Ohio benchmarks. The bill also removes the requirement for renewable resources to be located in Ohio. If passed, this legislation would make it easier for Ohio utilities to meet the state targets for energy efficiency and renewable energy.

The PUCO has found that DP&L met its renewable targets for compliance years 2008 – 2012. The PUCO Staff recommended that the PUCO find that DPLER met its targets for compliance year 2011. Filings for compliance year 2012 were made on April 15, 2013. Both DP&L and DPLER expect to be found in full compliance with all renewable targets. DP&L’s energy efficiency portfolio plan was also filed on April 15, 2013. Most parties to that case reached a settlement which was filed on October 2, 2013 and is pending PUCO approval.

Significantly Excessive Earnings Test

On September 9, 2009, the PUCO issued an order establishing a SEET proceeding pursuant to provisions contained in SB 221. The PUCO issued an order on June 30, 2010 to establish general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. The other three Ohio utilities were required to make their SEET determinations in 2012, 2011 and 2010. According to DP&L’s 2009 ESP stipulation, DP&L became subject to the SEET in 2013 based on 2012 earnings. On July 31, 2013, the Company filed its case at the PUCO demonstrating that its 2012 earnings were not significantly excessive. DP&L’s SEET review is expected to result in no adjustment to our SSO rates nor a refund to customers in 2013.

Reliability Targets

On June 29, 2012, DP&L filed its application to establish reliability targets consistent with the PUCO Electric Service and Safety Standards (ESSS). According to the ESSS rules, all Ohio utilities are subject to financial penalties if the established targets are not met for two consecutive years. DP&L and PUCO Staff reached a settlement establishing new reliability targets in this case. The settlement was approved by the PUCO on October 4, 2013.

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 have been meeting 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. This investigation is expected to result in recommendations being made to the PUCO Staff in January 2014. The outcome of this proceeding could have a material impact on DP&L’s operations and how it performs certain functions with respect to Ohio electric choice.

COMPETITION AND PJM PRICING

RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2016/17 period cleared at a per megawatt price of $59/day for our RTO area. The per megawatt prices for the periods 2015/16, 2014/15, 2013/14 and 2012/13 were $136/day, $126/day, $28/day and $16/day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. The SSO retail costs and revenues are included in the RPM rider. Therefore, increases in customer switching causes more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but based on actual results attained in 2012, we estimate that a hypothetical increase or decrease of $10 in the capacity auction price would result in an annual impact to net income of approximately $6.1 million and $4.8 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

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, beginning January 2014; ten percent of that supply will be sourced through the competitive bid auction discussed above. 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 ended September 30, 2013 and 2012:



	Three months ended				Three months ended
	September 30, 2013				September 30, 2012
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)

Supplied by DPLER ^(a)		118,458		1,575		59,241		1,671

Supplied by non-affiliated CRES providers		86,359		947		69,127		562

Total in our service territory		204,817		2,522		128,368		2,233

Distribution sales by DP&L in our service territory ^(b)		513,293		3,618		512,191		3,795

(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 44% and 44% of DP&L’s total distribution volumes during the three months ended September 30, 2013 and 2012, respectively. We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.



	Nine months ended				Nine months ended
	September 30, 2013				September 30, 2012
	Electric Customers		Sales (in millions of kWh)		Electric Customers		Sales (in millions of kWh)

Supplied by DPLER ^(a)		118,458		4,391		59,241		4,668

Supplied by non-affiliated CRES providers		86,359		2,592		69,127		1,428

Total in our service territory		204,817		6,983		128,368		6,096

Distribution sales by DP&L in our service territory ^(b)		513,293		10,461		512,191		10,694

(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 42% and 44% of DP&L’s total distribution volumes during the nine months ended September 30, 2013 and 2012, respectively. We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

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.

For the nine months ended September 30, 2013, approximately 67% of DP&L’s load was supplied by CRES providers with DPLER supplying 63% of the switched load. For the nine months ended September 30, 2013, customer switching negatively affected DPL’s gross margin by approximately $179.0 million compared to the 2012 effect of approximately $96.0 million. For the nine months ended September 30, 2013, customer switching negatively affected DP&L’s gross margin by approximately $229.9 million compared to the 2012 effect of $176.0 million.

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

FUEL AND RELATED COSTS

Fuel and Commodity Prices

The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues are affecting mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. For the year ending December 31, 2013, we have hedged substantially all our coal requirements to meet our committed sales. We may not be able to hedge the entire exposure of our operations from commodity price volatility. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.

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	2013		2012		2013		2012
Revenues:
Retail	$	336.5	$	387.2	$	973.1	$	1,060.7
Wholesale		73.2		43.5		155.4		78.2
RTO revenues		21.7		34.7		59.5		72.6
RTO capacity revenues		8.4		5.5		20.3		69.0
Other revenues		2.6		2.8		8.2		8.5
Other mark-to-market losses		(1.2)		(2.0)		(5.8)		(1.3)
Total revenues		441.2		471.7		1,210.7		1,287.7

Cost of revenues:
Fuel costs		100.2		119.2		272.0		278.8
Losses / (gains) from the sale of coal		(0.4)		3.1		1.9		8.4
Mark-to-market losses / (gains)		(0.1)		(9.6)		0.1		(8.2)
Total fuel		99.7		112.7		274.0		279.0

Purchased power		71.7		53.5		184.8		127.4
RTO charges		32.2		30.9		84.4		77.0
RTO capacity charges		10.6		5.9		24.2		62.3
Mark-to-market losses / (gains)		(1.4)		0.4		(10.8)		(0.9)
Total purchased power		113.1		90.7		282.6		265.8

Amortization of intangibles		1.8		24.2		5.3		71.2

Total cost of revenues		214.6		227.6		561.9		616.0

Gross margin ^(a)	$	226.6	$	244.1	$	648.8	$	671.7

Gross margin as a percentage of revenues		51%		52%		54%		52%

Operating income / (loss)	$	76.0	$	(1,761.3)	$	191.6	$	(1,644.7)

(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.

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,
	2013		2012		2013		2012

Heating degree days^(a)		67		110		3,490		2,828
Cooling degree days ^(a)		688		825		1,027		1,255

(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.

Since we plan to utilize our internal generating capacity to supply our retail customers’ needs first, increases in retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; our retail demand; retail demand elsewhere throughout the entire wholesale market area; our plants’ and other utility plants’ availability to sell into the wholesale market; and weather conditions across the multi-state region. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities not being utilized to meet our retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.

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



	Three months ended			Nine months ended
	September 30,			September 30,
$ in millions	2013 vs. 2012			2013 vs. 2012
Retail
Rate		$	(20.4)		$	(56.9)
Volume			(32.8)			(33.6)
Other miscellaneous			2.5			2.9
Total retail change			(50.7)			(87.6)

Wholesale
Rate			1.5			(22.7)
Volume			28.2			99.9
Total wholesale change			29.7			77.2

RTO capacity & other
RTO capacity and other revenues			(10.1)			(61.8)

Other
Unrealized MTM			0.8			(4.5)
Other			(0.2)			(0.3)
Total other revenue			0.6			(4.8)

Total revenues change		$	(30.5)		$	(77.0)

For the three months ended September 30, 2013, Revenues decreased $30.5 million to $441.2 million from $471.7 million in the same period of the prior year. This decrease was primarily the result of lower retail average rates and sales volume, decreased RTO capacity revenues, offset slightly by higher wholesale average rates and sales volumes and higher unrealized MTM gain.

Retail revenues decreased $50.7 million primarily due to customer switching as a result of increased levels of competition to provide transmission and generation services in our service territory. There was an increase in sales procured by DPLER and MC Squared outside our service territory, or off-system sales, however, the overall sales volume still decreased 8%. The rates offered to the off-system customers are lower than the rates in our service territory; therefore, average rates decreased 6%. The above resulted in an unfavorable $32.8 million retail sales volume variance and an unfavorable $20.4 million retail sales price variance. The volume variance is comprised of a $41.2 million decrease for DP&L sales to customers offset by an $8.4 million increase due to higher sales volume by DPLER and MC Squared. The decrease in both heating and cooling degree days also contributed to the decrease in revenue.

Wholesale revenues increased $29.7 million primarily as a result of a 65% increase in wholesale sales volume due to customer switching; which makes our generation available for wholesale sales, including a 3% increase in total net generation by our power plants. Also contributing was a 2% increase in average wholesale prices. This resulted in a favorable $28.2 million wholesale sales volume variance, including a favorable wholesale price variance of $1.5 million.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $10.1 million compared to the same period in 2012. This decrease in RTO capacity and other revenues was the result of a $13.0 million decrease in RTO transmission and congestion revenues due to a 2012 settlement related to PJM SECA revenues, offset slightly by a $2.9 million increase in revenues realized from the PJM capacity auction.

For the nine months ended September 30, 2013, Revenues decreased $77.0 million to $1,210.7 million from $1,287.7 million in the same period of the prior year. This decrease was primarily the result of lower retail and wholesale average rates, decreased RTO capacity revenues and lower unrealized MTM gains, offset slightly by higher wholesale sales volumes. Retail volumes remained relatively even.

Retail revenues decreased $87.6 million primarily due to customer switching as a result of increased levels of competition to provide transmission and generation services in our service territory. The effect of sales procured by DPLER and MC Squared outside our service territory, or off-system sales, caused sales volume to remain even, however, the rates offered to the off-system customers are lower than the rates in our service territory causing an overall 9% decrease in average rates. Weather also contributed to the variance; during the nine months ended September 30, 2013, there was a 23% increase in the number of heating degree days to 3,490 days from 2,828 days in 2012, however, cooling degree days dropped 18% to 1,027 days from 1,255 days in 2012. The above resulted in an unfavorable $56.9 million retail price variance including an unfavorable $33.6 million retail sales volume variance.

Wholesale revenues increased $77.2 million primarily as a result of a 128% increase in wholesale sales volume due to customer switching, which makes our generation available for wholesale sales, including a 12% increase in total net generation by our power plants, offset slightly by a 13% decrease in average wholesale prices. This resulted in a favorable $99.9 million wholesale sales volume variance offset by an unfavorable wholesale price variance of $22.7 million.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $61.8 million compared to the same period in 2012. This decrease in RTO capacity and other revenues was the result of a $48.7 million decrease in revenues realized from the PJM capacity auction, including a $13.1 million decrease in RTO transmission and congestion revenues due to a 2012 settlement related to PJM SECA revenues

DPL – Cost of Revenues

For the three months ended September 30, 2013:

Fuel costs, which include coal, gas, oil and emission allowance costs, decreased $13.0 million, or 12%, during the three months ended September 30, 2013 compared to the same period in the prior year. This decrease was largely due to a $19.0 million decrease in fuel costs due to an 18% decrease in the average fuel price per MWh, partially offset by a 3% increase in the volume of generation by our stations. Also contributing is $0.4 million of realized gains from DP&L’s sale of coal in 2013 compared to $3.1 million of losses in the same period of 2012. These decreases were partially offset by decreased unrealized fuel MTM gains of $9.5 million in 2013 as compared to 2012.

Purchased power increased $22.4 million, or 25%, compared to the same period in the prior year due primarily to an $18.2 million increase in purchased power costs driven by an increase in purchased power volumes of $17 million, or 32%, primarily as a result of increased power purchases to supply DPLER sales, coupled with an increase in purchased power prices of approximately 2%. RTO capacity and other charges, which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers also increased by $6.0 million. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges, and is due to the higher PJM capacity auction price for the third quarter of 2013 compared to the third quarter of 2012. We purchase power to satisfy retail sales volume outside of our service territory as well as inside our service territory when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

·	Amortization of intangibles decreased $22.4 million compared to the same period in the prior year, due primarily to the ESP intangible asset that was fully amortized in December 2012.

For the nine months ended September 30, 2013:

Fuel costs, which include coal, gas, oil and emission allowance costs, decreased $5.0 million, or 2%, during the nine months ended September 30, 2013 compared to the same period in the prior year. This decrease was largely due to a $6.8 million decrease in fuel costs due to a 12% decrease in the volume of generation by our stations combined with a 13% decrease in the average fuel price per MWh. In addition realized losses from DP&L’s sale of coal decreased by $6.5 million. Partially offsetting these decreases were decreased unrealized fuel MTM gains of $8.3 million.

Purchased power increased $16.8 million, or 6%, compared to the same period in the prior year due largely to a $57.4 million increase in purchased power costs due to an increase in purchased power volumes of $45.2 million, or 36%, as a result of increased power purchases to supply DPLER sales, coupled with an increase in purchased power prices of approximately 7%. Offsetting this increase was a $30.7 million decrease in RTO capacity and other charges, which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges, and is due to the lower PJM capacity auction price for the nine months ending September 30, 2013 compared to the same period in 2012. While PJM capacity costs increased for the three month period ending September 30, 2013 above, the PJM capacity year runs from June 1 to May 31 each year. Also offsetting the increase in net purchased power costs were increased unrealized purchased power MTM gains of approximately $9.9 million. We purchase power to satisfy retail sales volume outside of our service territory as well as inside our service territory when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

·	Amortization of intangibles decreased $65.9 million compared to the same period in the prior year, due primarily to the ESP intangible asset that was fully amortized in December 2012.

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	2013 vs. 2012			2013 vs. 2012

Low-income payment program ⁽¹⁾		$	(1.5)		$	(3.8)
Generating facilities operating and maintenance expense			(4.6)			(15.2)
Maintenance of overhead transmission and distribution lines			(4.1)			(5.5)
Competitive retail operations			3.9			10.3
Other, net			(3.0)			(0.5)
Total change in operation and maintenance expense		$	(9.3)		$	(14.7)

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

During the three months ended September 30, 2013, Operation and maintenance expense decreased $9.3 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 expenses for generating facilities largely due to outages in the second quarter of 2012 at jointly owned production units relative to the same period in 2013; and

·	decreased expenses related to the maintenance of overhead transmission and distribution lines due to the Derecho storm in late June 2012 and July 2012 and decreased non-storm related expenses.

These decreases were partially offset by:

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

During the nine months ended September 30, 2013, Operation and maintenance expense decreased $14.7 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 expenses for generating facilities largely due to outages in the first and second quarters of 2012 at jointly owned production units relative to the same periods in 2013; and

·	decreased expenses related to the maintenance of overhead transmission and distribution lines due to the Derecho storm repairs in late June 2012 and July 2012 and decreased non-storm related expenses.

These decreases were partially offset by:

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

DPL – Depreciation and Amortization

For the three and nine months ended September 30, 2013, Depreciation and amortization expense increased an immaterial amount compared to the same periods in the prior year.

DPL – General Taxes

For the three and nine months ended September 30, 2013, General taxes increased $3.7 million and $2.1 million, respectively, compared to the same periods in the prior year. These increases were primarily the result of the 2012 reversal of a 2012 property tax reserve related to the purchase accounting property revaluations combined with higher property tax accruals in 2013 compared to 2012, partially offset by an adjustment to the Commercial Activities Tax

DPL – Interest Expense

Interest expense recorded during the three and nine months ended September 30, 2013 did not fluctuate significantly from that recorded during the same periods in the prior year.

DPL – Income Tax Expense

For the three months ended September 30, 2013, Income tax expense decreased $8.9 million compared to 2012, primarily due to higher pre-tax income in 2012 (adjusted for the $1,850.0 million goodwill impairment) and a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2009 tax year.

For the nine months ended September 30, 2013, Income tax expense decreased $19.5 million compared to 2012, primarily due to higher pre-tax income in 2012 (adjusted for the $1,850.0 million goodwill impairment), a favorable resolution of the 2008 Internal Revenue Service examination in the first quarter of 2013, a 2013 deferred tax adjustment related to the expiration of the statutes of limitations on the 2007, 2008 and 2009 tax years and a 2012 adjustment to state deferred taxes.

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:

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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's SSO customers is primarily generated at eight coal-fired power plants and DP&L distributes electricity to more than 513,000 retail customers. 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 281,000 customers currently located throughout Ohio and Illinois. MC Squared, a Chicago-based retail electricity supplier, serves more than 131,000 customers in Northern Illinois. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L in 2013 and DP&L and PJM in 2012. DP&L sells power to DPLER and MC Squared under wholesale agreements. Under these agreements, intercompany sales from DP&L to DPLER and MC Squared are based on fixed-price contracts for each DPLER or MC Squared customer. The price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Other

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

Management primarily evaluates segment performance based on gross margin.

See Note 11 of Notes to DPL’s Condensed Consolidated Financial Statements for further discussion of DPL’s reportable segments.

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



	Three months ended
	September 30,				Increase /
$ in millions	2013		2012		(Decrease)

Utility	$	206.0	$	238.8	$	(32.8)
Competitive Retail		14.1		22.1		(8.0)
Other		7.6		(16.0)		23.6
Adjustments and eliminations		(1.1)		(0.8)		(0.3)
Total consolidated	$	226.6	$	244.1	$	(17.5)



	Nine months ended
	September 30,				Increase /
	2013		2012		(Decrease)

Utility	$	595.2	$	666.6	$	(71.4)
Competitive Retail		41.1		51.9		(10.8)
Other		15.3		(44.3)		59.6
Adjustments and eliminations		(2.8)		(2.5)		(0.3)
Total consolidated	$	648.8	$	671.7	$	(22.9)

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

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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	2013		2012		(Decrease)
Revenues:
Retail	$	140.9	$	147.2	$	(6.3)
RTO and other		(1.2)		(1.7)		0.5
Total revenues		139.7		145.5		(5.8)

Cost of revenues:
Purchased power		125.6		123.4		2.2

Gross margins (a)		14.1		22.1		(8.0)

Operation and maintenance expense		9.5		5.4		4.1
Other expenses		0.7		0.8		(0.1)
Total expenses		10.2		6.2		4.0

Earnings before income tax		3.9		15.9		(12.0)
Income tax expense		1.4		5.9		(4.5)
Net income	$	2.5	$	10.0	$	(7.5)

Gross margin as a percentage of revenues		10%		15%

Income Statement Highlights – Competitive Retail Segment



	Nine months ended
	September 30,				Increase /
$ in millions	2013		2012		(Decrease)
Revenues:
Retail	$	387.7	$	367.4	$	20.3
RTO and other		(5.8)		0.1		(5.9)
Total revenues		381.9		367.5		14.4

Cost of revenues:
Purchased power		340.8		315.6		25.2

Gross margins (a)		41.1		51.9		(10.8)

Operation and maintenance expense		26.7		16.4		10.3
Other expenses		2.4		2.2		0.2
Total expenses		29.1		18.6		10.5

Earnings before income tax		12.0		33.3		(21.3)
Income tax expense		4.3		15.8		(11.5)
Net income	$	7.7	$	17.5	$	(9.8)

Gross margin as a percentage of revenues		11%		14%

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

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Competitive Retail Segment – Revenue

For the three months ended September 30, 2013, the segment’s retail revenues decreased $6.3 million, or 4% compared to 2012. The decrease was primarily due to a $14.7 million negative price variance partially offset by a $8.3 million positive volume variance. Increased competition in the competitive retail electric service business in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 2,624 million kWh of power to approximately 281,000 customers during the three months ended September 30, 2013 compared to approximately 2,484 million kWh of power to more than 175,000 customers during the same period of the prior year.

For the nine months ended September 30, 2013, the segment’s retail revenues increased $20.3 million, or 6%, compared to 2012. The increase was primarily due to a $69.8 million positive volume variance partially offset by a $49.5 million negative price variance. Increased competition in the competitive retail electric service business in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 7,260 million kWh of power to approximately 281,000 customers for the nine months ended September 30, 2013 compared to approximately 6,100 million kWh of power to approximately 175,000 customers during the same period of the prior year.

Competitive Retail Segment – Purchased Power

For the three months ended September 30, 2013, the segment’s purchased power increased $2.2 million, or 2%, compared to 2012 due to higher purchased power volumes partially offset by favorable prices for the power required to satisfy an increase in customer base resulting from customer switching. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM.

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

For the nine months ended September 30, 2013, the segment’s purchased power increased $25.2 million, or 8%, compared to 2012 due to higher purchased power volumes partially offset by favorable prices for the power required to satisfy an increase in customer base resulting from customer switching. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM.

Competitive Retail Segment – Operation and Maintenance

For the three and nine months ended September 30, 2013, DPLER’s operation and maintenance expenses included employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2013 compared to 2012 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.

Competitive Retail Segment – Income Tax Expense

For the three and nine months ended September 30, 2013, the segment’s income tax expense decreased $4.5 million and $11.5 million, respectively, compared to the same periods in the prior year primarily due to decreased pre-tax income and a 2012 adjustment to state deferred taxes.

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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	2013		2012		2013		2012

Revenues:
Retail	$	196.5	$	240.9	$	588.1	$	696.3
Wholesale		189.8		150.9		480.1		351.2
RTO revenues		19.9		33.5		56.6		69.2
RTO capacity revenues		7.0		4.7		17.0		58.7
Other mark-to-market losses		(0.1)		(3.2)		(0.3)		(2.4)
Total revenues		413.1		426.8		1,141.5		1,173.0

Cost of revenues:
Fuel costs		97.2		114.7		267.6		272.1
Losses / (gains) from the sale of coal		(0.4)		3.1		1.9		8.4
Mark-to-market losses / (gains)		(0.1)		(9.7)		0.1		(8.2)
Total fuel		96.7		108.1		269.6		272.3

Purchased power		70.1		42.4		179.9		99.0
RTO charges		30.9		29.7		82.4		74.5
RTO capacity charges		10.6		5.7		23.9		58.3
Mark-to-market losses / (gains)		(1.2)		2.1		(9.5)		2.3
Total purchased power		110.4		79.9		276.7		234.1

Total cost of revenues		207.1		188.0		546.3		506.4

Gross margin ^(a)	$	206.0	$	238.8	$	595.2	$	666.6

Gross margin as a percentage of
revenues		50%		56%		52%		57%

Operating Income	$	64.4	$	3.6	$	162.9	$	125.6

(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 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	2013 vs. 2012			2013 vs. 2012

Retail
Rate		$	(4.7)		$	(7.3)
Volume			(41.2)			(103.3)
Other miscellaneous			1.5			2.4
Total retail change			(44.4)			(108.2)

Wholesale
Rate			(10.1)			(71.0)
Volume			49.0			199.9
Total wholesale change			38.9			128.9

RTO capacity & other
RTO capacity and other revenues			(11.3)			(54.3)

Other
Unrealized MTM			3.1			2.1
Total other revenue			3.1			2.1

Total revenues change		$	(13.7)		$	(31.5)

For the three months ended September 30, 2013, Revenues decreased $13.7 million to $413.1 million from $426.8 million in the prior year. This decrease was the result of lower average retail and wholesale rates, lower retail sales volumes and decreased RTO transmission and congestion revenues, offset by increased wholesale sales volume. The revenue components for the three months ended September 30, 2013 are further discussed below:

Retail revenues decreased $44.4 million primarily due to a 17% decrease in retail sales volumes compared to the prior year which was a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. Average retail rates decreased 2% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The above resulted in an unfavorable $41.2 million retail sales volume variance and an unfavorable $4.7 million retail price variance. The decrease in both heating and cooling degree days also contributed to the decrease in revenue.

Wholesale revenues increased $38.9 million as a result of an increase in wholesale sales volume which was largely a result of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. Also contributing was a 4% increase in net generation available from DP&L’s co-owned and operated generation plants. These increases were partially offset by a 5% decrease in average wholesale rates. These resulted in a favorable $49.0 million wholesale volume variance offset by a $10.1 million unfavorable wholesale price variance.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $11.3 million compared to the same period in 2012. The decrease in RTO capacity and other revenues was a result of a $13.6 million decrease in RTO transmission and congestion revenues due to a 2012 settlement related to PJM SECA revenues, offset slightly by a $2.3 million increase in revenues realized from the PJM capacity auction.

For the nine months ended September 30, 2013, Revenues decreased $31.5 million to $1,141.5 million from $1,173.0 million in the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail sales volume, and decreased RTO capacity and other revenues, offset slightly by increased

105

wholesale sales volume. The revenue components for the nine months ended September 30, 2013 are further discussed below:

Retail revenues decreased $108.2 million primarily due to a 15% decrease in retail sales volumes compared to the prior year which was a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. Weather also contributed to the variance; during the nine months ended September 30, 2013, there was a 23% increase in the number of heating degree days to 3,490 days from 2,828 days for the same period in the prior year, however cooling degree days dropped 18% to 1,027 days from 1,255 days in 2012. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. Average retail rates decreased slightly overall, primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The above resulted in an unfavorable $103.3 million retail sales volume variance and an unfavorable $7.3 million retail price variance.

Wholesale revenues increased $128.9 million as a result of an increase in wholesale sales volume which was largely a result of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. Also contributing was a 14% increase in net generation available from DP&L’s co-owned and operated generation plants. These increases were partially offset by a 13% decrease in average wholesale rates. These resulted in a favorable $199.9 million wholesale volume variance offset by a $71.0 million unfavorable wholesale price variance.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $54.3 million compared to the same period in 2012. This decrease in RTO capacity and other revenues was primarily the result of a $41.7 million decrease in revenues realized from the PJM capacity auction, including a $12.6 million decrease in RTO transmission and congestion revenues due to a 2012 settlement related to PJM SECA revenues.

DP&L – Cost of Revenues

For the three months ended September 30, 2013:

Fuel costs, which include coal, gas, oil and emission allowance costs, decreased $11.4 million, or 11%, during the three months ended September 30, 2013 compared to the same period in the prior year. This decrease was largely due to a $17.5 million decrease in fuel costs due to a 19% decrease in the average fuel price per MWh partially offset by an increase in the volume of generation by our stations of 4%. Additionally, a $3.5 million decrease in realized losses from DP&L’s sale of coal contributed to the decrease in overall fuel costs. Partially offsetting these decreases were unrealized fuel MTM gains of $0.1 million for the three months ended September 30, 2013, compared to $9.7 million of unrealized fuel MTM gains during the same period in the prior year.

Purchased power increased $30.5 million, or 38%, compared to the same period in the prior year due largely to an increase in purchased power costs of $27.7 million, compared to the same period in the prior year. The increase in purchased power costs was driven by an increase in purchased power volumes of 57%, as a result of an increase in purchased power to supply DPLER sales, coupled with an increase in purchased power prices of approximately 5%. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. Further contributing to the increase in purchased power costs was a $6.1 million increase in RTO capacity and other charges, which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges, and is due to the higher PJM capacity auction price for the third quarter of 2013 compared to the third quarter of 2012. Offsetting these increases was a $3.3 million decrease in unrealized purchased power MTM losses.

For the nine months ended September 30, 2013:

Fuel costs, which include coal, gas, oil and emission allowance costs, decreased $2.7 million, or 1%, during the nine months ended September 30, 2013 compared to the same period in the prior year. This decrease was largely due to a $4.5 million decrease in fuel costs due to a 14% decrease in the average fuel price per MWh offset by a 14% increase in the volume of generation by our stations. Contributing to the overall decrease was a $6.5 million decrease in realized losses from DP&L’s sale of coal. The net decreases above were partially offset by an $8.3 million decrease in unrealized fuel MTM gains.

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Purchased power increased $42.6 million, or 18%, compared to the same period in the prior year due largely to an increase in purchased power costs of $80.9 million compared to the same period in the prior year. The increase in purchased power costs was driven by an increase in purchased power volumes of 72%, as a result of increased purchased power to supply DPLER sales, coupled with an increase in purchased power prices of approximately 6%. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities. Partially offsetting the increase in purchased power costs was a $26.5 million decrease in RTO capacity and other charges, which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges, and is due to the lower PJM capacity auction price in 2013 compared to 2012. Also offsetting the increase in purchased power costs was an $11.8 million increase in unrealized purchased power MTM gains.

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	2013 vs. 2012			2013 vs. 2012

Low-income payment program ⁽¹⁾		$	(1.5)		$	(3.8)
Generating facilities operating and maintenance expense			(4.5)			(15.1)
Maintenance of overhead transmission and distribution lines			(4.1)			(5.5)
Other, net			(5.9)			(4.0)
Total change in operation and maintenance expense		$	(16.0)		$	(28.4)

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

For the three months ended September 30, 2013, Operation and maintenance expense decreased $16.0 million compared to the same period in the prior year. This variance was primarily the result of:

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

·	decreased expenses for generating facilities largely due to outages in the third quarter of 2012 at jointly owned production units relative to the same period in 2013; and

·	decreased maintenance of overhead transmission and distribution lines due to the Derecho storm repairs in late June 2012 and July 2012 and decreased non-storm related expenses.

For the nine months ended September 30, 2013, Operation and maintenance expense decreased $28.4 million compared to the same period in the prior year. This variance was primarily the result of:

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

·	decreased expenses for generating facilities largely due to outages in the first and second quarters of 2012 at jointly owned production units relative to the same periods in 2013; and

·	decreased maintenance of overhead transmission and distribution lines due to the Derecho storm repairs in late June 2012 and July 2012 and decreased non-storm related expenses.

DP&L – Depreciation and Amortization

For the three and nine months ended September 30, 2013, Depreciation and amortization expense decreased an immaterial amount compared to the same periods in the prior year.

DP&L – General Taxes

For the three and nine months ended September 30, 2013, General taxes increased $3.9 million and $3.3 million, respectively, compared to the same periods in the prior year. The increase in the quarter was primarily

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due to the 2012 reversal of a property tax reserve related to the purchase accounting property revaluations. The increase in the year to date expense was primarily the result of higher property tax accruals in 2013 compared to 2012 offset partially by an adjustment to the Commercial Activities Tax.

DP&L – Interest Expense

Interest expense recorded during the three and nine months ended September 30, 2013 did not fluctuate significantly from that recorded during the same periods in the prior year.

DP&L – Income Tax Expense

For the three months ended September 30, 2013, Income tax expense increased $6.7 million compared to 2012, primarily due to increases in pre-tax income partially offset by a 2013 deferred tax adjustment related to the expiration of the statute of limitations on the 2009 tax and a 2012 adjustment for non-deductible executive compensation and a 2012 adjustment of property-related deferred taxes.

For the nine months ended September 30, 2013, Income tax expense decreased $10.2 million compared to 2012, primarily due to a favorable resolution of the 2008 Internal Revenue Service examination in the first quarter of 2013 and a 2013 deferred tax adjustment related to the expiration of the statutes of limitations on the 2007, 2008 and 2009 tax years, a 2012 adjustment for non-deductible executive compensation and a 2012 adjustment of property-related deferred taxes partially offset by increases in pre-tax income.

FINANCIAL CONDITION, Liquidity AND Capital ReQUIREMENTS

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



DPL	Nine months ended September 30,
$ in millions	2013			2012

Net cash from operating activities		$	249.1	$	254.5
Net cash from investing activities			(89.6)		(168.3)
Net cash from financing activities			207.5		(54.1)
Net change in cash and cash equivalents			367.0		32.1
Cash and cash equivalents at beginning of period			192.1		173.5
Cash and cash equivalents at end of period		$	559.1	$	205.6



DP&L	Nine months ended September 30,
$ in millions	2013			2012

Net cash from operating activities		$	283.9	$	304.6
Net cash from investing activities			(83.8)		(171.7)
Net cash from financing activities			281.8		(145.7)
Net change in cash and cash equivalents			481.9		(12.8)
Cash and cash equivalents at beginning of period			28.5		32.2
Cash and cash equivalents at end of period		$	510.4	$	19.4

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

Net cash provided by operating activities

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

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DPL – Net cash from operating activities

DPL’s Net cash from operating activities for the nine months ended September 30, 2013 and 2012 is summarized as follows:



	Nine months ended September 30,
$ in millions	2013			2012

Net cash from operating activities
Net income / (loss)		$	76.0	$	(1,777.3)
Depreciation and amortization			90.0		152.6
Deferred income taxes			31.5		(10.5)
Goodwill impairment			-		1,850.0
Accrued interest			24.3		25.2
Deferred regulatory costs, net			11.6		2.7
Prepaid taxes			0.7		0.6
Other operating activities, net			15.0		11.2
Net cash from operating activities		$	249.1	$	254.5

During the nine months ended September 30, 2013, Net cash provided by operating activities was primarily a result of Net income adjusted for non-cash depreciation and amortization, deferred income taxes, an increase in accrued interest and recovery of certain regulatory costs. Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily affected by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, taxes and when cash is received from our utility customers and from the sales of coal and excess emission allowances. Depreciation and amortization in 2013 was less than the same period in 2012 due to the full amortization of the ESP intangible in 2012.

During the nine months ended September 30, 2012, Net cash provided by operating activities was primarily a result of Net income adjusted for non-cash depreciation and amortization, non-cash goodwill impairment and accrued interest. Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily affected by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, taxes and when cash is received from our utility customers and from the sales of coal and excess emission allowances.

DP&L – Net cash from operating activities

DP&L’s Net cash from operating activities for the nine months ended September 30, 2013 and 2012 is summarized as follows:



	Nine months ended September 30,
$ in millions	2013			2012

Net cash from operating activities
Net income		$	101.5	$	58.3
Depreciation and amortization			104.5		107.3
Deferred income taxes			27.1		(3.4)
Fixed asset impairment			-		80.8
Recognition of deferred SECA revenue			-		(17.8)
Decrease in current assets			49.2		41.1
Accrued interest			2.7		7.4
Deferred regulatory costs, net			12.4		2.4
Prepaid taxes			0.8		0.8
Other operating activities, net			(14.3)		27.7
Net cash from operating activities		$	283.9	$	304.6

During the nine months ended September 30, 2013 and 2012, the significant components of DP&L’s Net cash provided by operating activities are similar to those discussed under DPL’s Net cash provided by operating activities above. In addition, current assets, including receivables, inventories and taxes applicable to subsequent years decreased, creating positive cash flow from working capital.

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DPL – Net cash from investing activities

DPL’s Net cash from investing activities for the nine months ended September 30, 2013 and 2012 is summarized as follows:



	Nine months ended September 30,
$ in millions	2013			2012

Net cash from investing activities
Capital expenditures		$	(96.5)	$	(163.1)
Environmental and renewable energy capital expenditures			(3.3)		(4.8)
(Increase) / decrease in restricted cash			3.4		(0.4)
Insurance proceeds			7.6		-
Other investing activities, net			(0.8)		-
Net cash from investing activities		$	(89.6)	$	(168.3)

During the nine months ended September 30, 2013 and 2012, DPL’s Net cash used for investing activities was primarily for assets acquired at our generation plants.

DP&L – Net cash from investing activities

DP&L’s Net cash from investing activities for the nine months ended September 30, 2013 and 2012 is summarized as follows:



	Nine months ended September 30,
$ in millions	2013			2012

Net cash from investing activities
Capital expenditures		$	(95.1)	$	(161.7)
Environmental and renewable energy capital expenditures			(3.3)		(4.8)
(Increase) / decrease in restricted cash			3.4		(5.2)
Insurance proceeds			12.1		-
Other investing activities, net			(0.9)		-
Net cash from investing activities		$	(83.8)	$	(171.7)

During the nine months ended September 30, 2013 and 2012, the significant components of DP&L’s Net cash used for investing activities are similar to those discussed under DPL’s Net cash used for investing activities above.

DPL – Net cash from financing activities

DPL’s Net cash from financing activities for the nine months ended September 30, 2013 and 2012 is summarized as follows:



	Nine months ended September 30,
$ in millions	2013			2012

Net cash from financing activities
Dividends paid on common stock to parent		$	-	$	(45.0)
Contributions to paid-in capital from parent			-		0.3
Payment to former warrant holders			-		(9.0)
Deferred finance costs			(11.6)		(0.3)
Borrowings from revolving credit facilities			50.0		-
Repayment of borrowings from revolving credit facilities			(50.0)		-
Issuance of long-term debt, net			644.2		-
Retirement of long-term debt			(425.1)		(0.1)
Net cash from financing activities		$	207.5	$	(54.1)

During the nine months ended September 30, 2013 DPL paid costs associated with the refinancing of various debt agreements, paid off its $425.0 million term loan, borrowed and repaid $50.0 million on its revolving credit

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facility, and borrowed $200.0 million on its new term loan. DP&L also issued $445.0 million in first mortgage bonds.

During the nine months ended September 30, 2012, DPL paid common stock dividends of $45.0 million to its parent, partially offset by contributions to additional paid-in capital from its parent, AES. DPL also paid $9.0 million to former warrant holders, the payment of which represents the difference between the exercise price of $21.00 per share and the $30.00 per share paid by AES in the Merger.

DP&L – Net cash from financing activities

DP&L’s Net cash from financing activities for the nine months ended September 30, 2013 and 2012 is summarized as follows:



	Nine months ended September 30,
$ in millions	2013			2012

Net cash from financing activities
Dividends paid on common stock to parent		$	(155.0)	$	(145.0)
Issuance of long-term debt, net			444.2		-
Deferred finance costs			(6.7)		-
Other financing activities, net			(0.7)		(0.7)
Net cash from financing activities		$	281.8	$	(145.7)

During the nine months ended September 30, 2013, DP&L’s Net cash used for financing activities relates to dividends paid to DPL and the issuance of $445.0 million of first mortgage bonds.

During the nine months ended 2012, DP&L’s Net cash used for financing activities relates to dividends paid.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments. For 2013, and in subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from 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 manage working capital requirements during those periods.

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



$ in millions	Type	Maturity	Commitment		Amounts available as of September 30, 2013

DP&L	Revolving	May 2018	$	300.0	$	299.6

DPL	Revolving	May 2018		100.0		100.0

			$	400.0	$	399.6

DP&L’s revolving 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. DP&L had no outstanding borrowings under this facility at September 30, 2013. At September 30, 2013, there was a letter of credit in the amount of $0.4 million outstanding, with the remaining $299.6 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 shall 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

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and a feature which provides DPL the ability to increase the size of the facility by an additional $50.0 million. As of June 30, 2013, DPL had drawn $50.0 million under this facility and these outstanding borrowings were repaid in full on July 10, 2013 and as of September 30, 2013, there were no letters of credit issued and outstanding against the revolving credit facilities. On August 7, 2013, DP&L issued an immaterial letter of credit against its revolving credit facility.

Cash and cash equivalents for DPL and DP&L amounted to $559.1 million and $510.4 million, respectively, at September 30, 2013. At that date, neither DPL nor DP&L had any short-term investments that were not included in cash and cash equivalents.

On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. On October 1, 2013, DP&L used the net proceeds of this new issue, along with cash on hand, to redeem, at par value, the $470.0 million of first mortgage bonds that matured on October 1, 2013.

In May 2013, DP&L amended the JPMorgan Chase Bank, N.A. standby letters of credit of approximately $100.0 million that were scheduled to expire in December 2013 and that support the 2040 VRDNs. The amendment extended the maturities until June 2018. These amended facilities are irrevocable and remain subject to terms and conditions that are substantially similar to those of the pre-existing facilities.

Capital Requirements

Planned construction additions for 2013 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors.

DPL is projecting to spend an estimated $445.0 million in capital projects for the period 2013 through 2015, of which $430.0 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 $72.0 million within the next five years to reinforce its 138 kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

Debt Covenants

As discussed above, in May 2013 DPL terminated its then existing $75.0 million revolving credit facility and $425.0 million term loan and replaced them with a new $100.0 million revolving credit facility and a drawn $200.0 million term loan facility.

Each of the facilities that were terminated in May had two financial covenants, one of which was changed as part of amendments, dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups. The first financial covenant, originally a Total Debt to Capitalization ratio, was changed, effective September 30, 2012, to a Total Debt to EBITDA ratio. The Total Debt to EBITDA ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The new DPL revolving credit facility and the new DPL term loan agreement will continue to 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 new agreements is not to exceed 8.50 to 1.00 for the fiscal quarter ending June 30, 2013 through December 31, 2014; it then steps down to not exceed 8.00 to 1.00 for the fiscal quarter ending March 31, 2015 through December 31, 2016; and it then steps down not to exceed 7.50 to 1.00 for the fiscal quarter ending March 31, 2017 through March 31, 2018. As of September 30, 2013, the financial covenant was met with a ratio of 6.18 to 1.00.

The new DPL revolving credit facility and the new DPL term loan agreement 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 new agreements is not to be less than 2.00 to 1.00 for the fiscal quarter ending June 30, 2013 through December 31,

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2014; it then steps up to not to be less than 2.10 to 1.00 for the 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 the fiscal quarter ending March 31, 2017 through March 31, 2018. As of September 30, 2013, the financial covenant was met with a ratio of 3.71 to 1.00.

The amendments, dated October 19, 2012, to the facilities negotiated between DPL and the syndicated bank groups, and to DPL’s new unsecured revolving credit agreement and DPL’s new unsecured term loan both executed on May 10, 2010 restrict dividend payments from DPL to AES and adjust the cost of borrowing under the facilities under certain rating scenarios.

Also, as discussed above, in May 2013 DP&L terminated its two $200.0 million revolving credit facilities and replaced them with a new $300.0 million revolving credit facility.

DP&L’s new 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, 2013, this covenant was met with a ratio of 0.51 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 new DP&L revolving credit facility will also have an EBITDA to Interest Expense ratio that will be 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. DP&L’s EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. As of September 30, 2013, this covenant was met with a ratio of 7.92 to 1.00.

Debt Ratings

On September 9th and September 10th, 2013, Moody’s and Fitch, respectively, downgraded DPL and DP&L ratings and updated their outlooks to stable. The following tables outline the debt and credit 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 2013
Moody's Investors Service, Inc.	Ba2	Baa1	Stable	September 2013
Standard & Poor's Financial Services LLC	BB	BBB-	Stable	April 2013

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

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

Credit Ratings

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



	DPL	DP&L	Outlook	Effective

Fitch Ratings	B+	BB+	Stable	September 2013
Moody's Investors Service, Inc.	Ba2	Baa3	Stable	September 2013
Standard & Poor's Financial Services LLC	BB	BB	Stable	April 2013

If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts. These events may have an adverse effect on our results of operations, financial

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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 ended September 30, 2013, DPL did not incur any losses related to the guarantees of these obligations, and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.

At September 30, 2013, DPL had $18.0 million of guarantees to third parties, for future financial or performance assurance under such agreements, on behalf of DPLE, DPLER and MC Squared. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $0.7 million at September 30, 2013.

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, 2013, DP&L could be responsible for the repayment of 4.9%, or $76.9 million, of a $1,569.8 million debt obligation that features maturities ranging from 2018 to 2040. This would only happen if this electric generation company defaulted on its debt payments. As of September 30, 2013, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

Also see Note 10 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 of Notes to DP&L’s Condensed Financial Statements.

Market Risk

We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emissions and gas, changes in capacity prices and fluctuations in interest rates. We use various market risk sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing. Our Commodity Risk Management Committee (CRMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures relating to our DP&L-operated generation units. The CRMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.

Commodity Pricing Risk

Commodity pricing risk exposure includes the impacts of weather, market demand, increased competition and other economic conditions. To manage the volatility relating to these exposures at our DP&L-operated generation units, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market unless they qualify for cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis and where applicable, we recognize a corresponding Regulatory asset for above-market costs or a Regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.

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The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2013 under contract, sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January 2010, our results of operations, financial condition or cash flows could be materially affected.

For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.

Commodity Derivatives

To minimize the risk of fluctuations in the market price of commodities, such as coal, power and heating oil, we may enter into commodity-forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between us and the counter-party at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months.

A 10% increase or decrease in the market price of our heating oil forwards at September 30, 2013 would not have a significant effect on Net income.

A 10% increase or decrease in the market price of our forward power purchase contracts 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 $17.3 million.

Wholesale Revenues

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



DPL	Three months ended				Nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
Percent of electric revenues from wholesale market		18%		10%		15%		11%

DP&L	Three months ended				Nine months ended
	September 30,				September 30,
	2013		2012		2013		2012
Percent of electric revenues from wholesale market		48%		36%		44%		35%

The following table presents the effect on annual Net income as of September 30, 2013, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note that the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):



$ in millions	DPL		DP&L
Effect of 10% change in price per MWh	$	9.9	$	8.3

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

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runs from June 1 to May 31, has conducted auctions for capacity through the delivery year. The clearing prices for capacity during the PJM delivery periods from 2012/13 through 2016/17 are as follows:



	PJM Delivery Year
($/MW-day)	2012/13		2013/14		2014/15		2015/16		2016/17
Capacity clearing price	$	16	$	28	$	126	$	136	$	59

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



	Calendar Year
($/MW-day)	2012		2013		2014		2015		2016
Computed average capacity price	$	55	$	23	$	85	$	132	$	91

Future RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJM’s RPM business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s capacity revenues and costs. Although DP&L currently has an approved RPM rider in place to recover or repay any excess capacity costs or revenues, the RPM rider only applies to customers supplied under our SSO. Customer switching reduces the number of customers supplied under our SSO, causing more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.

The following table provides estimates of the effect on annual Net income as of September 30, 2013 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO. These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through September 30, 2013. As of September 30, 2013, approximately 25% 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	$	6.1	$	4.8

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

Fuel and Purchased Power Costs

DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the nine months ended September 30, 2013 and 2012 were 45% and 38%, respectively. We have a significant portion of projected 2013 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO₂allowances for 2013; however, the exact consumption of SO₂allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NO_x allowances for 2013 depending on NO_x emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.

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

Effective January 1, 2010, DP&L was allowed to recover its SSO retail customers’ share of fuel and purchased power costs as part of the fuel rider approved by the PUCO. Since there has been an increase in customer switching, SSO customers currently represent approximately 25% of DP&L’s total fuel costs.

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The following table provides the effect on annual net income as of September 30, 2013, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 25% recovery:



$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	28.8	$	28.2

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’s Condensed 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. As of September 30, 2013, DPL has settled 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 $2,818.5 million at September 30, 2013, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds, capital leases and the Wright-Patterson Air Force Base note. All of DPL’s debt was adjusted to fair value at the Merger date according to FASC 805. The fair value of this debt at September 30, 2013 was $2,855.3 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:



DPL
	Principal payments due
	during the twelve months ending												At September 30, 2013
	September 30,												Principal		Fair
$ in millions	2014		2015		2016		2017		2018		Thereafter		Amount		Value

Variable-rate debt	$	10.0	$	40.0	$	40.0	$	40.0	$	70.0	$	100.0	$	300.0	$	300.0
Average interest rate		2.4%		2.4%		2.4%		2.4%		2.4%		0.1%
Fixed-rate debt	$	470.3	$	0.1	$	445.1	$	450.1	$	0.1	$	1,152.8		2,518.5		2,555.3
Average interest rate		5.1%		4.2%		1.9%		6.5%		4.2%		6.6%

Total													$	2,818.5	$	2,855.3

The carrying value of DP&L’s debt was $1,347.2 million at September 30, 2013, consisting of its first mortgage bonds, tax-exempt pollution control bonds, capital leases and the Wright-Patterson Air Force Base note. The fair value of this debt was $1,330.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides 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.

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DP&L
	Principal payments due
	during the twelve months ending												At September 30, 2013
	September 30,												Principal		Fair
$ in millions	2014		2015		2016		2017		2018		Thereafter		Amount		Value

Variable-rate debt	$	-	$	-	$	-	$	-	$	-	$	100.0	$	100.0	$	100.0
Average interest rate		0.0%		0.0%		0.0%		0.0%		0.0%		0.1%
Fixed-rate debt	$	470.3	$	0.1	$	445.1	$	0.1	$	0.1	$	331.5		1,247.2		1,230.8
Average interest rate		5.1%		4.2%		1.9%		4.2%		4.2%		4.8%

Total													$	1,347.2	$	1,330.8

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

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at September 30, 2013 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of September 30, 2013, we did not hold any market risk sensitive instruments which 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, 2013				One percent
	Carrying		Fair		interest rate
$ in millions	Value		Value		risk
Long-term debt

Variable-rate debt	$	300.0	$	300.0	$	3.0

Fixed-rate debt		2,514.5		2,555.3		25.6

Total	$	2,814.5	$	2,855.3	$	28.6



DP&L	At September 30, 2013				One percent
	Carrying		Fair		interest rate
$ in millions	Value		Value		risk
Long-term debt

Variable-rate debt	$	100.0	$	100.0	$	1.0

Fixed-rate debt		1,247.2		1,230.8		12.3

Total	$	1,347.2	$	1,330.8	$	13.3

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

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percentage point in interest rates has on the fair value of DPL’s $2,555.3 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 $300.0 million variable-rate long-term debt outstanding as of September 30, 2013.

DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $1,230.8 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $100.0 million variable-rate long-term debt outstanding as of September 30, 2013.

Equity Price Risk

As of September 30, 2013, approximately 28% of the defined benefit pension plan assets were comprised of investments in equity securities and 72% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. We use an investment adviser to assist in managing our investment portfolio. The market value of the equity securities was approximately $ 96.6 million at September 30, 2013. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9.7 million reduction in fair value of the equity securities as of September 30, 2013.

Credit Risk

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

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; and assets and liabilities related to employee benefits. Refer to our Form 10-K for the fiscal year ended December 31, 2012 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.

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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,
	2013		2012		2013		2012		2013		2012

Electric Sales (millions of kWh)		5,414		5,072		5,343		4,775		2,624		2,484

Billed electric customers (end of period)		675,592		628,381		513,309		512,219		280,741		175,403

(a) This table contains electric sales from DP&L’s generation and purchased power. DP&L sold 1,575 million kWh and 1,671 million kWh of power to DPLER during the three months ended September 30, 2013 and 2012, respectively, not included above to avoid duplication.

(b) This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory.



	DPL				DP&L ^(a)				DPLER ^(b)
	Nine months ended				Nine months ended				Nine months ended
	September 30,				September 30,				September 30,
	2013		2012		2013		2012		2013		2012

Electric Sales (millions of kWh)		14,437		12,323		14,312		11,502		7,260		6,100

Billed electric customers (end of period)		675,592		628,381		513,309		512,219		280,741		175,403

(a) This table contains electric sales from DP&L’s generation and purchased power. DP&L sold 4,391 million kWh and 4,668 million kWh of power to DPLER during the nine months ended September 30, 2013 and 2012, respectively, not included above to avoid duplication.

(b) This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

See the “MARKET RISK” section in Item 2 of this Part I, which is incorporated by reference into this item.

Item 4. Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries 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.

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There was no change in our internal control over financial reporting during the quarter ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Part II

Item 1. Legal Proceedings

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

Our Form 10-K for the fiscal year ended December 31, 2012, and the Notes to the Consolidated Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II of our Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Form 10-K, and should be read in conjunction with the Form 10-K.

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

Item 1A. Risk Factors

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

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

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

On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008. This law, among other things, required all Ohio distribution utilities to file either an ESP or MRO, and established a SEET for Ohio public utilities that compares the utility’s earnings to the earnings of other companies with similar business and financial risks. The PUCO approved DP&L’s first ESP on June 24, 2009 and second ESP on September 6, 2013. The second ESP which takes effect January 2014 will result in changes to the current rate structure and riders that could adversely affect our results of operations, cash flows and financial condition. DP&L’s ESP and certain filings made by us in connection with this plan are further

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discussed under “Regulatory Environment” in Part 1, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

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

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None

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Item 6. Exhibits


DPL Inc.	DP&L	Exhibit Number		Exhibit		Location

	X	4(a)	Registration Rights Agreement, dated as of September 19, 2013, by and between Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC, as representatives of the initial purchasers		Exhibit 4.1 to Report on Form 8-K filed September 25, 2013 (File No. 1-2385)
	X	4(b)	47^th Supplemental Indenture to the First and Refunding Mortgage, dated as of September 1, 2013, by and between the Bank of New York Mellon, as Trustee, and The Dayton Power and Light Company		Exhibit 4.2 to Report on Form 8-K filed September 25, 2013 (File No. 1-2385)


X		31(a)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 31(a)
X		31(b)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 31(b)
	X	31(c)		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 31(c)
	X	31(d)		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 31(d)
X		32(a)		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 32(a)
X		32(b)		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 32(b)
	X	32(c)		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 32(c)
	X	32(d)		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		Filed herewith as Exhibit 32(d)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location

X	X	101.INS	XBRL Instance	Furnished herewith as Exhibit 101.INS
X	X	101.SCH	XBRL Taxonomy Extension Schema	Furnished herewith as Exhibit 101.SCH
X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Furnished herewith as Exhibit 101.CAL
X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Furnished herewith as Exhibit 101.DEF
X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Furnished herewith as Exhibit 101.LAB
X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Furnished herewith as Exhibit 101.PRE

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

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SIGNATURES

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



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



Date:	November 6, 2013	/s/ Philip R. Herrington
		(Philip R. Herrington)
		Chief Executive Officer
		(principal executive officer)



	November 6, 2013	/s/ Craig L. Jackson
		(Craig L. Jackson)
		Senior Vice President and Chief Financial Officer
		(principal financial officer)



	November 6, 2013	/s/ Kurt A. Tornquist
		(Kurt A. Tornquist)
		Controller
		(principal accounting officer)

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