UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K/A
Amendment No. 110-K

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

For the fiscal year ended December 31, 20152016

OR

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

For the transition period from ____________ to ____________


Commission
File Number
 
Registrant, State of Incorporation,
Address and Telephone Number
 

I.R.S. Employer 
Identification No.
     
1-9052 DPL INC. 31-1163136
  (An Ohio Corporation)  
  
1065 Woodman Drive
Dayton, Ohio 45432
  
  937-224-6000937-259-7215  
     
1-2385 THE DAYTON POWER AND LIGHT COMPANY 31-0258470
  (An Ohio Corporation)  
  
1065 Woodman Drive
Dayton, Ohio 45432
  
  937-224-6000937-259-7215  

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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


Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

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


1

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 xo
No ox
The Dayton Power and Light Company
Yes o
No x

DPL Inc. and The Dayton Power and Light Company is aare voluntary filerfilers that has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months. During 2015, DPL Inc. was a voluntary filer until its May 29, 2015 Registration Statement on Form S-4 filed with the Securities and Exchange Commission was declared effective on June 12, 2015. DPL Inc. hashave 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 website, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K/A10-K or any amendment to this Form 10-K/A.10-K.

DPL Inc.x
The Dayton Power and Light Companyx

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 definitions of “accelerated filer, large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 Large Non-Smaller
 acceleratedAcceleratedacceleratedreporting
 filerfilerfilercompany
DPL Inc.ooxo
The Dayton Power and Light Companyooxo

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.


2

At December 31, 2015,2016, each registrant had the following shares of common stock outstanding:

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


Documents incorporated by reference: None

This combined Form 10-K/A10-K 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.

THE REGISTRANTS MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K/A10-K AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.

3

Explanatory Note

We are filing this Amendment No. 1 (“Form 10-K/A”) to our combined Annual Report on Form 10-K for the fiscal year ended December 31, 2015, as filed with the Securities and Exchange Commission (the “SEC”) on February 24, 2016 (the “Form 10-K”), to correct the following inadvertent administrative error: the Reports of Independent Registered Public Accounting Firm previously filed with the Form 10-K have been amended to include the electronic signatures of Ernst & Young LLP on such reports for both DPL Inc. and The Dayton Power and Light Company, which signatures had been obtained prior to our filing the Form 10-K.
In accordance with Rule 12b-15 under the Securities Exchange Act of 1934, as amended, each item of the Form 10-K that is amended by this Form 10-K/A is restated in its entirety, and this Form 10-K/A is accompanied by restated and re-executed certifications on Exhibits 31(a) – (d) and Exhibits 32(a) – (d) by our Chief Executive Officer and Chief Financial Officer.
This Form 10-K/A speaks as of the original filing date of the Form 10-K and does not reflect any events that may have occurred subsequent to the original filing date. Except as described above, no other changes have been made to the Form 10-K and we are not amending any other part of, or updating any other disclosures made in, the Form 10K.


4

DPL Inc. and The Dayton Power and Light Company

Table of Contents
Amendment No. 1 to Annual Report on Form 10-K
Fiscal Year Ended December 31, 20152016

Glossary of Terms 
65
Part I
Item 1 – Business
9
Item 1A – Risk Factors
21
Item 1B – Unresolved Staff Comments
33
Item 2 – Properties
33
Item 3 – Legal Proceedings
33
Item 4 – Mine Safety Disclosures
33
Part II 
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
33
Item 6 – Selected Financial Data
35
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations
36
Item 7A – Quantitative and Qualitative Disclosures about Market Risk
72
Item 8 – Financial Statements and Supplementary Data
 
DPL Inc.
1179
The Dayton Power and Light Company
70135
Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
184
Item 9A – Controls and Procedures
184
Item 9B – Other Information
184
Part III
Item 10 – Directors, Executive Officers and Corporate Governance
185
Item 11 – Executive Compensation
185
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
185
Item 13 – Certain Relationships and Related Transactions, and Director Independence
185
Item 14 – Principal Accountant Fees and Services
185
Part IV 
Item 15 – Exhibits and Financial Statement Schedules
122186
Item 16 – Form 10-K Summary
191
Signatures
127192
Schedule II – Valuation and Qualifying Accounts
195

5

GLOSSARY OF TERMS

The following select terms, abbreviations or acronyms are used in this Form 10-K/A:10-K:

Abbreviation or AcronymDefinition
AEP GenerationAEP Generation Resources Inc., a subsidiary of American Electric Power Company, Inc. (“AEP”). Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011. The Ohio Power generating assets (including jointly-owned units) were transferred into AEP Generation, effective January 1, 2014.
AERAlternative Energy Rider which allows DP&L to recover costs related to meeting the Ohio renewable portfolio standards.Generation.
AESThe AES Corporation, a global power company, the ultimate parent company of DPL
AES Ohio GenerationAES Ohio Generation, LLC, (formerly DPLE), a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale salessales. AES Ohio Generation, LLC was formerly known as DPL Energy, LLC.
AFUDCAllowance for Funds Used During Construction
AMIAdvanced Metering Infrastructure
AOCIAccumulated Other Comprehensive Income
AROAsset Retirement Obligation
ASUAccounting Standards Update
CFTCCommodity Futures Trading Commission
CAAU.S. Clean Air Act
CAIRClean Air Interstate Rule
Capacity MarketThe purpose of the capacity market is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. PJM procures capacity, through a multi-auction structure, on behalf of the load serving entities to satisfy the load obligations. There are four 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 there is one Incremental Auction held in each of the subsequent three years. Both DP&L’s and AES Ohio Generation's capacity is located in the “rest of” RTO area of PJM.
CCEMCustomer Conservation and Energy Management
CO2
Carbon Dioxide
ComEdCommonwealth Edison
CPIn 2015, PJM adopted changes to the capacity market known as “Capacity Performance”. The CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours.” The DP&L and AES Ohio Generation units will operate under the CP construct starting June 1, 2016.
CRESCompetitive Retail Electric Service
CSAPRCross-State Air Pollution Rule
CWAU.S. Clean Water Act
Dark spreadA common metric used to estimate returns over fuel costs of coal-fired electric generating unitsEGUs
D.C. Circuit CourtUnited States Court of Appeals for the District of Columbia Circuit
DPLDPL Inc.
DPLEDPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales (renamed AES Ohio Generation, LLC effective February 1, 2016)
DPLERDPL Energy Resources, Inc., formerly a wholly-owned subsidiary of DPL which sold competitive electric energy and other energy services, including sales by a wholly-owned subsidiary, MC Squared, which DPLER sold on April 1, 2015. DPLER was sold by DPL on January 1, 2016. The DPLER sale2016 pursuant to an agreement was signed ondated December 28, 2015.

6

GLOSSARY OF TERMS (cont.)
Abbreviation or AcronymDefinition
DP&LThe Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells, transmits and distributes electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L is wholly-owned by DPL
DthsDecatherms, unit of heat energy equal to 10 therms. One therm is equal to 100,000 British Thermal Units
Duke EnergyAffiliates of Duke Energy with which DP&L co-owns electric generating units and transmission lines in Ohio (Duke Energy Ohio, Inc.)
DynegyDynegy, Inc., the parent of various subsidiaries that, along with AEP Generation and DP&L, co-owns electric generating unitscoal-fired EGUs in Ohio

GLOSSARY OF TERMS (cont.)
Abbreviation or AcronymDefinition
EBITDAEarnings before interest, taxes, depreciation and amortization
EGUElectric generating unit
ERISAThe Employee Retirement Income Security Act of 1974
ESPThe Electric Security Plan is a cost-based plan that a utility may file with the PUCO to establish SSO rates pursuant to Ohio law
ESP 1ESP approved by PUCO order dated June 24, 2009
ESP 2ESP approved by PUCO order dated September 4, 2013. The Ohio Supreme Court ruled that it was invalid. DP&L withdrew its ESP 2 on July 27, 2016 and filed an amended application on October 11, 2016.
ESP 3ESP filed with the PUCO by DP&L on February 22, 2016
FASBFinancial Accounting Standards Board
FASCFASB Accounting Standards Codification
FASC 805FASB Accounting Standards Codification 805, “Business Combinations”
FERCFederal Energy Regulatory Commission
FGDFlue Gas Desulfurization
First and Refunding MortgageDP&L’s First and Refunding Mortgage, dated October 1, 1935, as amended, with the Bank of New York Mellon as Trustee
FTRsFTRFinancial Transmission Rights
GAAPGenerally Accepted Accounting Principles in the United States of America
GHGGreenhouse gas
IFRSInternational Financial Reporting Standards
kVKilovolts, 1,000 volts
kWhKilowatt hour
LIBORLondon Inter-Bank Offering Rate
Master TrustDP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans
MATSMercury and Air Toxics Standards
MC SquaredMC Squared Energy Services, LLC, a retail electricity supplier formerly wholly-owned by DPLER, sold on April 1, 2015
MergerThe merger of DPL and Dolphin Sub, Inc. (a wholly-owned subsidiary of AES) in accordance with the terms of an Agreement and Plan of Merger dated April 19, 2011 among DPL, AES and Dolphin Sub, Inc. a wholly-owned subsidiary of AES. On the Merger date, DPL became aan indirect wholly-owned subsidiary of AES.
Merger dateNovember 28, 2011, the date of the closing of the merger of DPL and Dolphin Sub, Inc.
MROMarket Rate Option, a market-based plan that a utility may file with PUCO to establish SSO rates pursuant to Ohio law
MTMMark to Market
MVICMiami 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 relative to jointly-owned facilities operated by DP&L
MWMegawatt
MWhMegawatt hour
NAAQSNational Ambient Air Quality Standards
NAVNet asset value
NERCNorth American Electric Reliability Corporation
Non-bypassableCharges that are assessed to all customers regardless of whom the customer selects as their retail electric generation supplier
NOVNotice of Violation
NOX
Nitrogen Oxide
NPDESNational Pollutant Discharge Elimination System
NSRNew Source Review is a preconstruction permitting program regulating new or significantly modified sources of air pollution

7

GLOSSARY OF TERMS (cont.)
Abbreviation or AcronymDefinition
NPDESNational Pollutant Discharge Elimination System
NSPSNew Source Performance Standards
NSR New Source Review is a preconstruction permitting program regulating new or significantly modified sources of air pollution
NYMEXNew York Mercantile Exchange
OAQDAOhio Air Quality Development Authority
OCCOhio Consumers’ Counsel
OCIOther Comprehensive Income
Ohio EPAOhio Environmental Protection Agency
OTCOver the counter
OVECOhio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest
PJMPJM Interconnection, LLC, an RTO
PPMParts per million
PRPPotentially Responsible Party
PredecessorDPL prior to the Merger date
PUCOPublic Utilities Commission of Ohio
ROEReturn on equity
RPMThe Reliability Pricing Model was PJM’s capacity construct.
RTORegional Transmission Organization
SB 221Ohio Senate Bill 221 is 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.
SB 310Ohio Senate Bill 310, an Ohio electric energy bill that was passed in May 2014 that required all Ohio utilities to show on each bill the approximate cost of complying with renewable energy, energy efficiency and peak demand requirements. It froze the Ohio renewable and energy efficiency annual targets for two yearyears and required a legislative committee to evaluate whether or not the targets should continue. 
SCRSelective Catalytic Reduction
SECSecurities and Exchange Commission
SEETSignificantly Excessive Earnings Test
Service CompanyAES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses
SFASStatement of Financial Accounting Standards
SIPA 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
SSOStandard Service Offer represents the retail transmission, distribution and generation services offered by thea utility through regulated rates, authorized by the PUCO
SSRService Stability Rider
SuccessorDPL after the Merger
TCRRTransmission Cost Recovery Rider
TCRR-BTransmission Cost Recovery Rider – Bypassable

8

GLOSSARY OF TERMS (cont.)
Abbreviation or AcronymDefinition
TCRR-NTransmission Cost Recovery Rider – Nonbypassable
USEPAU. S. Environmental Protection Agency
USFThe Universal Service Fund (USF) is a statewide program which provides qualified low-income customers in Ohio with income-based bills and energy efficiency education programs
U.S. SBUU. S. Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL
VIEVariable Interest Entity is an entity in which the investor holds a controlling interest that is not based on the majority of voting rights.

PART I

This report includes the combined filing of DPL and DP&L. DPL is 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 condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of future economic performance, taking into account the information currently available to management. These statements are not statements of historical fact and are typically identified by terms and phrases such as “anticipate”, “believe”, “intend”, “estimate”, “expect”, “continue”, “should”, “could”, “may”, “plan”, “project”, “predict”, “will” and similar expressions. Such forward-looking statements are subject to risks and uncertainties and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to:

abnormal or severe weather and catastrophic weather-related damage;
unusual maintenance or repair requirements;
changes in fuel costs and purchased power, coal, environmental emission allowances, natural gas and other commodity prices;
volatility and changes in markets for electricity and other energy-related commodities;
performance of our suppliers;
increased competition and deregulation in the electric utility industry;
increased competition in the retail generation market;
availability and price of capacity;
changes in interest rates;
state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws;
9changes 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 and changes in our credit ratings and availability and cost of capital;
changes in tax laws and the effects of our strategies to reduce tax payments;
the outcomes of litigation and regulatory investigations, proceedings or inquiries;
general economic conditions; and
the risks and other factors discussed in this report and other DPL and DP&L filings with the SEC.
Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change

in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

Table
Item 1 – Business
OVERVIEW

DPL is a regional energy company incorporated in 1985 under the laws of ContentsOhio. DPL was acquired by The AES Corporation on November 28, 2011 and DPL’s stock is owned by an AES subsidiary.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribution services are still regulated. DP&L has the exclusive right to provide such service to its approximately 519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity atfivecoal-fired power stations. Beginning January 2016, all of the electric supply for SSO customers is competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells energy and capacity into the wholesale market. Through December 31, 2015, DP&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER's retail customers.

DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations.

DPL’s other significant subsidiaries include AES Ohio Generation, 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 other subsidiaries. DPL owns all of the common stock of its subsidiaries.

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

DP&L does not have any subsidiaries.

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

SEGMENTS
DPL manages the business through two reportable operating segments, the Transmission and Distribution segment and the Generation segment. See Note 14 – Business Segments of the Notes to DPL’s Consolidated Financial Statements for additional information regarding DPL’s reportable segments.

DP&L also manages the business through two reportable operating segments, the Transmission and Distribution segment and the Generation segment. See Note 13 – Business Segments of the Notes to DP&L’s Consolidated Financial Statements for additional information regarding DP&L’s reportable segments.

EMPLOYEES
DPL and its subsidiaries employed 1,168 people at January 31, 2017. At that date, 1,160 of these employees were employed by DP&L. Approximately 62% of the employees of DPL and its subsidiaries are under a collective bargaining agreement which expires on October 31, 2017.

SERVICE COMPANY
Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other services of a similar nature on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated businesses served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.

ELECTRIC OPERATIONS AND FUEL SUPPLY

2016 Summer Generating Capacity
(in MW)
DPL's and DP&L's present summer generating capacity is in the following table:
Summer Generating CapacityCoal fired
(percent of total)		 Combustion Turbines, Diesel Units and Solar
(percent of total)		 Total
DPL2,078
 68% 988
 32% 3,066
          
DP&L2,078
 83% 432
 17% 2,510

100% of DP&L’s existing steam generating capacity is provided by generating units owned as tenants in common with Dynegy, Inc. and AEP Generation. As tenants in common, each company owns a specified share of each of these units, is entitled to its share of capacity and energy output and has a capital and operating cost responsibility proportionate to its ownership share. Additionally, DP&L, Duke Energy and AEP Generation own, as tenants in common, 880 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.

In 2016, we generated 93% of our electric output from coal-fired units and 7% from solar, oil and natural gas-fired units.


The following table sets forth DP&L’s and AES Ohio Generation’s generating stations and, where indicated, those stations which DP&L owns as tenants in common:
        Approximate Summer MW Rating
Station 
Ownership (1)
 Operating Company Location 
DPL Portion (2)
 Total
Coal Units        
Killen - Unit 2 C DP&L Wrightsville, OH 402
 600
Stuart - Units 1 through 4 ⁽³⁾ C DP&L Aberdeen, OH 808
 2,308
Conesville - Unit 4 C AEP Generation Conesville, OH 129
 780
Miami Fort - Units 7 & 8 C Dynegy North Bend, OH 368
 1,020
Zimmer - Unit 1 C Dynegy Moscow, OH 371
 1,320
Sub-total coal       2,078
 6,028
Solar, Combustion Turbines (CT) or Diesel        
Hutchings CT Unit 7 W DP&L Miamisburg, OH 25
 25
Yankee Units 1 - 7 W DP&L Centerville, OH 101
 101
Yankee Solar W DP&L Centerville, OH 1
 1
Monument Diesels W DP&L Dayton, OH 12
 12
Tait Diesels W DP&L Dayton, OH 10
 10
Sidney Diesels W DP&L Sidney, OH 12
 12
Tait CT Units 1 - 3 W DP&L Moraine, OH 256
 256
Killen CT C DP&L Wrightsville, OH 12
 18
Stuart Diesels C DP&L Aberdeen, OH 3
 10
Montpelier CT Units 1 - 4 W AES Ohio Generation Poneto, IN 236
 236
Tait CT Units 4 - 7 W AES Ohio Generation Moraine, OH 320
 320
Sub-total solar, CT or diesel   988
 1,001
           
Total approximate summer generating capacity   3,066
 7,029

(1)W = Wholly-owned C = Commonly-owned
(2)
DP&L portion of commonly-owned generating stations
(3)On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As the damage assessment process is currently ongoing, we cannot determine the impact to operations or capacity at this time.

In addition to the above, DP&L also owns a 4.9% equity ownership interest in OVEC, an electric generating company. OVEC has two electric generating stations located in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of 2,109 MW. DP&L’s share of this generation capacity is 103 MW.

We have all of the coal volume needed to meet our wholesale sales obligations for 2017 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled/forced outages and generation station mix. Due to the installation of emission control equipment at certain commonly-owned units and barring any changes in the regulatory environment in which we operate, we expect to have balanced positions for SO2, NOx and renewable energy credits for 2017. The gross average cost of fuel consumed per kWh was as follows:
 
Average cost of Fuel Consumed
(cents per kWh)
 2016 2015 2014
DPL2.30 2.48 2.52
      
DP&L2.22 2.42 2.45


SEASONALITY

The power generation and delivery business is seasonal and weather patterns have a material effect on operating performance. In the region we serve, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating compared to other times of the year. Unusually mild summers and winters could have an adverse effect on our results of operations, financial condition and cash flows.

MARKET STRUCTURE

Retail rate regulation
The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

DP&L's delivery service to all retail customers as well as the provisions of its SSO service are regulated by the PUCO. In addition, certain costs are considered to be non-bypassable and are therefore assessed to all DP&L retail customers, under the regulatory authority of the PUCO, regardless of the customer’s retail electric supplier. DP&L's transmission rates and wholesale electric rates are subject to regulation by the FERC under the Federal Power Act.

Ohio law establishes the process for determining SSO and non-bypassable rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate changes, the cost basis upon which the rates are set and other service-related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.

Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCO's supervisory powers to a holding company system's general condition and capitalization, among other matters, to the extent that such matters relate to the costs associated with the provision of public utility service. Based on existing PUCO and FERC authorization, regulatory assets and liabilities are recorded on the balance sheets of both DPL and DP&L. See Note 3 – Regulatory Matters of Notes to DPL’s Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s Financial Statements.

COMPETITION AND REGULATION

Ohio Matters

Ohio Retail Rates
Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. The terms and conditions of DP&L’s current SSO are provided under the most-recently approved ESP. Although it had been in effect since January 2014, on June 20, 2016, the Ohio Supreme Court (Court) issued an opinion in the appeal of DP&L’s ESP that had been approved by the PUCO for the years 2014 - 2016 and which, among other matters, permitted DP&L to collect a non-bypassable SSR equal to $110 million per year from 2014 - 2016 and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. DP&L’s own generation was phased-out of supplying SSO service over the three-year period. Beginning January 1, 2016, DP&L's SSO was 100% sourced through the competitive bid. In the opinion, the Court stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP and implement rates consistent with those in effect prior to 2014. Those rates will be in effect until rates consistent with DP&L’s pending ESP 3 filing are approved and effective.

For more information regarding DP&L's ESP, See Note 3 – Regulatory Matters of Notes to DPL’s Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s Financial Statements.

The costs associated with providing high voltage transmission service and wholesale electric sales and ancillary services are subject to FERC jurisdiction. While DP&L has market-based rate authority for wholesale electric sales, DP&L would be required to file an application at FERC under section 101 of Title 18 of the Code of Federal Regulations to change any of its cost-based transmission or ancillary service rates.

On October 30, 2015, DP&L publicly announced its intent to file an application to increase its distribution rates at the PUCO. On November 30, 2015, DP&L filed its distribution rate case using a 12-month test year of June 1,

2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015 to measure its asset base. DP&L is seeking an increase to distribution revenues of $65.8 million per year. DP&L has asked for recovery of certain regulatory assets as well as two new riders that would allow DP&L to recover certain costs on an ongoing basis. It has proposed a modified straight-fixed variable rate design in an effort to decouple distribution revenues from electric sales. If approved as filed, the rates are expected to have an effect of approximately 4% on a typical residential customer bill based on rates in effect at the time of the filing.

Ohio law and the PUCO rules contain targets relating to renewable energy, peak demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. DP&L is in full compliance with energy efficiency, peak demand reduction and renewable targets.

Ohio Senate Bill 310 was introduced in 2014 and became effective September 12, 2014. The law changes several aspects of the renewable energy and energy efficiency sections of Ohio law. The law freezes the renewable energy requirements at 2014 levels for 2015 and 2016 and the energy efficiency requirements if a utility modifies its portfolio plan. SB 310 removed the advanced energy requirement and removed the requirement that renewable energy had to be procured through facilities located within the state. DP&L did not file an amended portfolio plan, thereby extending its current plan through 2016. In 2016, DP&L filed a new energy efficiency portfolio plan for the years 2017 through 2019. Ultimately, DP&L entered into a settlement agreement (which is subject to PUCO approval), under which it has agreed to an extension of its current plan with slight changes through 2017 and has agreed to file a plan by June 2017 for programs in years 2018 through 2020. For additional information on this settlement agreement, see "Management's Discussion and Analysis of Financial Condition - Key Trends and Uncertainties - Regulatory Environment". DP&L recovers the costs of its compliance with Ohio energy efficiency and renewable energy standards through separate riders which are reviewed and audited by the PUCO.

As a member of PJM, DP&L receives revenues from the RTO related to DP&L’s transmission and generation assets and incurs costs associated with its load obligations for retail customers. Ohio law includes a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. DP&L’s TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs associated with the portion of SSO DP&L supplied with its generation. Beginning January 1, 2016, DP&L’s generation is no longer used to supply SSO, therefore DP&L will no longer recover its PJM RPM and market based transmission costs through retail rates. It will continue to recover non-market based transmission costs through its TCRR-N.

DP&L and AES Ohio Generation have filed an application before the FERC to adjust their rates with respect to reactive power provided to PJM from their generation units. The proposed rate changes have been referred to a FERC administrative law judge for settlement discussions and, if a settlement cannot be reached, the proposal will be referred to administrative hearings. At this time we are unable to predict the likelihood of reaching a settlement or what the final approved rates will be, although we do not expect the changes from current reactive power rates to be material. Additionally, the FERC has referred to FERC’s Office of Enforcement for investigation, an issue regarding reactive power charges under the previously effective rates in light of changes in DP&L’s generation portfolio. DP&L's reactive power rates were last reset in 1998. As of the date of this report, DP&L is unable to predict the ultimate outcome of the investigation. Several other utilities within PJM are also being investigated by FERC’s Office of Enforcement on the same issue of changes in the generation portfolio that occurred in between rate proceedings.

DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The PUCO previously established DP&L’s ROE SEET threshold at 12%. On May 15, 2016, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2015. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015. That case is still pending. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows.

Ohio Competition
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 procure and provide electricity to SSO customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

Competitive Generation
Market prices for power, as well as government aggregation initiatives, have led and may continue to lead to the entrance of additional competitors in our service territory. Beginning January 1, 2016, 100% of SSO load has been supplied through the competitive bid auction. After that date, customer switching no longer has an effect on DP&L’s margin.

Like other electric utilities and energy marketers, DP&L and AES Ohio Generation may sell or purchase electric products in the wholesale market. DP&L and AES Ohio Generation compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of DP&L and AES Ohio Generation to sell this electricity will depend not only on the performance of our generating units, but also on how DP&L's and AES Ohio Generation’s prices, terms and conditions compare to those of other suppliers.

As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities were required to join an RTO. In October 2004, DP&L successfully integrated its high-voltage transmission lines into the PJM RTO. The role of the RTO is to administer a competitive wholesale market for electricity and ensure reliability of the transmission grid. PJM ensures the reliability of the high-voltage electric power system serving more than 50 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid, administers the world’s largest competitive wholesale electricity market and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.

Capacity Auction Price
The PJM capacity base residual auction for the 2019/20 period cleared at a price of $100/MW-day for our RTO area. The prices for the periods 2018/19, 2017/18 and 2016/17 were $165/MW-day, $152/MW-day and $134/MW-day, respectively, based on previous auctions. As discussed below, a new CP program was approved by the FERC, which will phase in and replace RPM as of the 2018/19 period. During the phase-in period, the RPM auction results were modified based on transitional auctions that were conducted in the third quarter of 2015. We cannot predict the outcome of future auctions but based on actual results attained, we estimate that a hypothetical increase or decrease of $10/MW-day in the capacity auction price would result in an annual impact to net income of approximately $5.9 million and $4.9 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect capacity revenues and costs such as our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Item 7A - Quantitative and Qualitative disclosures about Market Risk.

On June 9, 2015, the FERC approved a proposal made by PJM to implement a new CP program. The FERC’s conditions on approval include requiring PJM to make additional filings to change certain energy market rules to coordinate better with the new CP program and to make annual filings on the CP performance hours used in its calculations. The FERC’s order approved transitional mechanisms under which the results of the auctions under the RPM program for the 2016/17 and 2017/18 periods would be modified based on transitional CP auctions that were held in the third quarter of 2015. The first full CP auction was also held in the third quarter of 2015 for the 2018/19 period.

As approved, the CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours”. This linkage between non- or under-performance during certain specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net Cost of New Entry, which is a value computed by PJM. This level is likely to be larger than the capacity price established under the CP program, so that the potential exists that participation in the CP program could result in capacity penalties that exceed capacity revenues.

PJM’s transition from the RPM to CP construct began with transitional auctions for the 2016/17 and 2017/18 Delivery Years, and the transition will be complete with full CP procurement in the auction this May for the 2020/21 Delivery Year. The biggest risk associated with the CP construct is the potential for significant penalties that could exceed revenues if a CP event is declared by PJM and the units do not perform at the committed levels during the event. The 2016/17 Delivery Year was the first to include the CP product and thus far there have been no CP

events called by PJM. The capacity clearing prices for the CP auctions have continued to demonstrate the volatility that was associated with the RPM construct.

ENVIRONMENTAL MATTERS

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

The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions,
Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,
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Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO2, particulates, mercury, acid gases, NOX, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,
Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs,
Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows. See Note 12 – Contractual Obligations, Commercial Commitments and Contingencies – "Environmental Matters” of Notes to DPL’s Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies – "Environmental Matters" of Notes to DP&L’s Financial Statements for more information regarding environmental risks, laws and regulations and legal proceedings to which we are and may be subject to in the future.
We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.
Environmental Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on how much of a pollutant can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.
Cross-State Air Pollution Rule
On September 7, 2016, the USEPA finalized an update to the CSAPR to address the 2008 ozone NAAQS. CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. The final rule found that NOx ozone season emissions in 22 states (including Ohio) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS. For

these 22 states, the USEPA is issuing federal implementation plans that generally update existing CSAPR NOx ozone season emission budgets for electric generating units within these states, and implement these budgets through modifications to the existing CSAPR NOx ozone season allowance trading program. Implementation will start in the 2017 ozone season (May through September 2017). Affected facilities will receive fewer ozone season NOx allowances in 2017 and later, possiblyresulting in the need to purchase additional allowances. At this time, we cannot predict what the impact on our business will be with respect to these new standards and requirements, but it could be material if certain facilities will need to purchase additional allowances based on reduced allocations.
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 electric generating units. 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, with a compliance date of April 16, 2015. All of our operating EGUs are currently achieving compliance through control technologies in place.
On January 31, 2013, the USEPA finalized a rule regulating emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers and process heaters at major and area source facilities. This regulation affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulation contains emissions limitations, operating limitations and other requirements. As of the date of this report, DP&L is in material compliance with this rule.
National Ambient Air Quality Standards
On January 25, 2013, the USEPA published the 2012 PM 2.5 standard of 12.0 micrograms per cubic meter. On January 15, 2015, USEPA published its final designations for the 2012 standard. No counties containing DP&L operated generating facilities were designated as non-attainment; however, several co-owned units are located in non-attainment counties. Attainment in those counties will be required by the end of 2021. We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&L’s financial condition or results of operations.
On October 1, 2015, the USEPA released a final rule lowering the 8-hour ozone standard from 0.075 to 0.070 ppm. Ozone attainment determinations are expected by October 1, 2017. In December 2013, eight northeastern states petitioned the USEPA to add nine upwind states, including Ohio, to the Ozone Transport Region, a group of states required to impose enhanced restrictions on ozone emissions. On January 19, 2017, USEPA issued a proposed rule denying the petition. In addition, Maryland petitioned the USEPA in November 2016, asking the USEPA to determine that 36 electric generating units emit pollutants that contribute to non-attainment of the ozone standards in their state. The Killen unit was on the list of 36 units. If either of these petitions are granted, our facilities could be subject to additional requirements. We cannot predict the effect the revisions of the ozone standard will have on DP&L’s financial condition or results of operations.
Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO2 replacing the previous 24-hour standard and annual standard with a one-hour standard. Non-attainment areas will be required to meet the 2010 standard by October 2018. On August 21, 2015, the USEPA finalized a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO2 emissions. The rule could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations. DP&L is unable to determine the effect of the rule, 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, if any, on our operations until Ohio determines how BART will be implemented.

Carbon Dioxide and Other Greenhouse Gas Emissions
In January 2014, the USEPA proposed revised GHG New Source Performance Standards (NSPS) for new EGUs under CAA subsection 111(b), which would require new EGUs to limit the amount of CO2 emitted per megawatt-hour. The final NSPS was published in the Federal Register on October 23, 2015, and regulates CO2 emissions from new, modified and reconstructed fossil-fuel-fired power plants. The final rules are effective immediately.
On October 23, 2015, the USEPA's final CO2 emission rules for existing power plants (called the Clean Power Plan or "CPP") were published in the Federal Register with an effective date of December 22, 2015. The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved by 2030. Prior to the rule's publication in the Federal Register, fifteen states, including Ohio, filed a petition in the D.C. Circuit Court seeking a stay of the CPP, which was denied by the D.C. Circuit Court in September 2015. On October 23, 2015, several states and industry groups filed petitions in the D.C. Circuit Court challenging the CPP as published in the Federal Register, including a twenty-four state consortium that includes Ohio. These state petitioners, as well as industry groups separately challenging the rule, have filed motions with the D.C. Circuit Court requesting a stay of the rule. On January 21, 2016, the D.C. Circuit Court issued an order denying motions for stay of the rule, however on February 9, 2016, the U.S. Supreme Court stayed the rule pending action by the D.C. Circuit Court, and the stay will continue until the U.S. Supreme Court renders a decision if the D.C. Circuit Court action is appealed. The D.C. Circuit Court has also issued orders consolidating the current pending challenges to the CPP under the lead case, West Virginia v. EPA. On October 23, 2015, North Dakota filed a petition for review of the Greenhouse Gas NSPS in the D.C. Circuit Court, and a coalition of environmental groups have moved to intervene on behalf of the USEPA in both the CPP and NSPS litigation. Additional legal challenges to the CPP and NSPS are expected. It is too early to determine how the stay will impact implementation of the CPP. We are currently reviewing the CPP and Greenhouse Gas NSPs and assessing the impact on our operations. Our business, financial condition or results of operations could be materially and adversely affected by this rule.
Approximately 93% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 12 million tons annually. Further GHG legislation or regulation implemented at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L.
Litigation, Notices of Violation and Other Matters Related to Air Quality
Litigation Involving Co-Owned Stations
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 generating station are subject to certain specified emission targets related to NOX, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during startups. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.
Notices of Violation Involving Co-Owned Units
In June 2000, the USEPA issued an NOV to the DP&L-operated Stuart generating station (co-owned by DP&L, Dynegy and AEP Generation) 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. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.
On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and permits for the station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, the USEPA issued an NOV to Zimmer for excess emissions. In addition, Zimmer received an NOV from the USEPA dated December 16, 2014 alleging violations in opacity on two dates in 2014. DP&L is a co-owner of the Zimmer generating station and could be affected by

the eventual resolution of these matters. Dynegy 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.
In January 2015, DP&L received NOVs from the USEPA alleging violations in opacity at the Stuart and Killen generating stations in 2014. On February 15, 2017, the USEPA issued an NOV alleging violations in opacity at the Stuart generation station in 2016. DP&L is in the process of discussions with the USEPA on these NOVs. DP&L is unable to predict the outcome of these matters.
Notices of Violation Involving Wholly-Owned Stations
On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the two projects described in the NOV were modifications subject to NSR. As a result of the cessation of operations of the six coal-fired units at the Hutchings Station, DP&L believes that the USEPA is unlikely to pursue the NSR complaint.
Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds
Clean Water Act – Regulation of Water Intake
On May 19, 2014, the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. Although we do not yet know the full impact the final rules will have on our operations, the final rules may require material changes to the intake structure at Stuart Station to reduce impingement with the possibility of additional site specific requirements for reducing entrainment. We do not believe the final rules will have a material impact on operations at any of the other DP&L-operated facilities.
Clean Water Act – Regulation of Water Discharge
In December 2006, DP&L submitted a renewal application for the Stuart generating 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 did not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit would 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 required 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 their 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. Settlement discussions are ongoing. Depending on the outcome of the appeal process, the effects on DP&L’s operations could be material.
In September 2009, the USEPA announced that it would be revising technology-based regulations governing water discharges from steam electric generating facilities. The proposed rule was released on June 7, 2013, and a final rule was published on November 3, 2015 with an effective date of January 4, 2016. Under the provisions of the final rule, discharges from fly ash ponds and bottom ash ponds will eventually be prohibited and treatment will be required for water discharges associated with flue gas desulfurization equipment. We are still evaluating the final rule, and its impact on us will depend on the status of our operations at the affected plants. If we were required to fully implement the requirements of the rule based on current operations, we anticipate that we will be required to make significant capital expenditures that could have a material adverse effect on our results of operations, financial condition and cash flows.


Clean Water Act rules for Selenium
On July 13, 2016, the USEPA published the final updated chronic aquatic life criterion for the pollutant selenium in freshwater per section 304(a) of the CWA. The rule will be implemented after state rulemaking occurs, which is expected to be at the end of 2017, and requirements will be incorporated into NPDES permits with compliance schedules in some cases. We are reviewing the rule and cannot determine what the impact, if any, will be on our operations.
Regulation of Waste Disposal
In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (ASAOC) for the site was executed and became effective among a group of PRPs, not including DP&L, and the USEPA. On August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio (the District Court) against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the 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 District Court judge 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 District Court judge, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly delivered by truck directly to the landfill. Discovery, including depositions of past and present DP&L employees, was conducted in 2012. On February 8, 2013, the District Court judge granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by the PRP group in performing an RI/FS under the August 15, 2006 ASAOC. That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th Circuit affirmed the lower Court’s ruling and subsequently denied a request by the PRP group for rehearing. On November 14, 2014, the PRP group appealed the decision to the U.S. Supreme Court, but the writ of certiorari was denied by the Court on January 20, 2015. On April 5, 2013, the PRP group entered into a second ASAOC (the "2013 ASAOC") relating primarily to vapor intrusion from under some of the buildings at the landfill site. On April 13, 2013, as amended July 30, 2013, the PRP group filed another civil complaint against DP&L and numerous other defendants alleging that each defendant contributed to the contamination of the site by delivering hazardous waste to the site or by releasing hazardous waste on other sites that migrated to the landfill site.
On February 18, 2014, after considering various motions and alternative grounds to dismiss, the District Court judge dismissed some of the alleged grounds for relief that the PRP group had made, but ruled in the PRP group’s favor with respect to motions to dismiss the case in its entirety finding, among other things, that the 2013 ASAOC involved a different scope of work and thus the contributions sought were not seeking the same remedy that had been dismissed in the first civil suit. Appeals of this ruling are pending before the 6th Circuit Court of Appeals.
On January 14, 2015, the PRP group served DP&L and other defendants a request for production of documents related to any waste management or waste disposal surveys. Information responsive to this request was provided on February 17, 2015. In addition, on January 16, 2015, the USEPA issued a Special Notice Letter and Section 104(e) Information Request to DP&L and other defendants, requesting historical information related to waste management practices that may be relevant to the site. DP&L responded to this request on March 27, 2015. In June 2015, DP&L was again requested to grant access to the DP&L service building property for the purpose of collecting groundwater samples from selected monitoring wells. DP&L granted access and groundwater sampling took place in June 2015. As a result of an August 11, 2015 meeting among the parties, the parties agreed to stay the case in order to explore the possibility of a negotiated resolution of some or all of the issues. The stay ended February 7, 2016 without resolution of claims against

DP&L. A trial date has been set for May 2018. DP&L is currently engaging in discovery with other litigants and is unable to predict the outcome of these actions by the plaintiffs and USEPA. Additionally, the District Court’s 2013 ruling and the Court of Appeals’ affirmation of that ruling in 2014 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 and any future matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its business, financial condition or results of 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.
On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L. A proposed rule is expected in 2017. At present, DP&L is unable to predict the impact this initiative will have on its results of operations, financial condition or cash flows.
Regulation of Ash Ponds
The USEPA released a final rule on December 19, 2014, designating coal combustion residuals that are not beneficially reused as non-hazardous solid waste under the Resource Conservation Recovery Act (RCRA) Subtitle D. The rule became effective on October 19, 2015, and applies new detailed management practices to new and existing landfills and surface impoundments, including lateral expansions of such units. In 2015, DP&L increased the ARO related to ash ponds by a net $40.3 million as a result of this rule. In 2016, the DP&L ARO related to ash ponds increased by a net $37.5 million, primarily to reflect revised estimated closure expenditures as well as plant closure dates that are earlier than previously forecast.
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 generating 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 CWA 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 condition or cash flows.
In November 2016, Duke Energy announced a settlement with the U.S. Attorney's Office for the Southern District of Ohioassociated with an NOV issued by the USEPA for a fuel oil spill at the Beckjord station in 2014. DP&L at that time co-owned 50% of one of the units at the station and was generally responsible for that percentage of that unit’s costs. The settlement includes a $1M fine and a requirement to clean-up the spill at the station. DP&L's portion of the fine and cleanup of this spill based on its prior ownership of one unit at the station has not yet been determined.
Capital Expenditures for Environmental Matters
DP&L’s environmental capital expenditures were approximately $6.1 million, $6.5 million and $3.6 million in 2016, 2015 and 2014, respectively. DP&L has not projected any environmental-related capital expenditures for 2017.


ELECTRIC SALES AND REVENUES

The following table sets forth DPL’s, DP&L's and DPLER's electric sales for the years ended December 31, 2016, 2015 and 2014, as well as billed electric customers as of December 31, 2016, 2015 and 2014.

  Year ended December 31, 2016 Year ended December 31, 2015 Year ended December 31, 2014
  Electric sales (millions of kWh) Billed electric customers (end of period) Electric sales (millions of kWh) Billed electric customers (end of period) Electric sales (millions of kWh) Billed electric customers (end of period)
             
DPL (a)
 16,757
 519,128
 14,738
 516,708
 14,695
 515,622
             
DP&L (b)
 16,158
 519,128
 16,424
 516,708
 18,613
 515,622
             
DPLER (c)
 —
 —
 5,928
 124,866
 9,717
 260,097

(a)
Electric sales excludes 1,976 million kWh and 4,068 million kWh relating to DPLER for the years ended December 31, 2015 and 2014, respectively, and Billed electric customers excludes DPLER customers outside of the DP&L service territory of 14,147 customers and 128,861 customers for the years ended December 31, 2015 and 2014, respectively.
(b)
Included within this line are 3,952 million kWh and 5,649 million kWh of power that DP&L sold to DPLER within the DP&L service territory for the years ended December 31, 2015 and 2014, respectively.
(c)
This row includes all customers and sales of DPLER, both within and outside of the DP&L service territory.

HOW TO CONTACT DPL AND DP&L
DPL is a regional energy company incorporated in 1985 under the laws of Ohio. Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio 45432 - telephone 937-259-7215. DPL’s public internet site is http://www.dplinc.com. DP&L’s public internet site is http://www.dpandl.com. The information on these websites is not incorporated by reference into this report.

Item 1A – Risk Factors
Investors should consider carefully the following risk factors that could cause our business, operating results and financial condition to be materially adversely affected. 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. These risk factors should be read in conjunction with the other detailed information concerning DPL set forth in the Notes to DPL’s audited Consolidated Financial Statements and DP&L set forth in the Notes to DP&L’s audited Financial Statements in Item 8 – Financial Statements and Supplementary Data and in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations herein. The risks and uncertainties described below are not the only ones that we face.

Our electric generating facilities are subject to operational risks that could result inunscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costsand other significant liabilitiesfor which we may not have adequate insurance coverage.
We operate coal, oil and natural gas generating facilities, which involve certain risks that can adversely affect energy costs, output and efficiency levels. These risks include:

increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;
unit or facility outages due to a breakdown or failure of equipment or processes;
disruptions in the availability or delivery of fuel and lack of adequate inventories;
shortages of or delays in obtaining equipment;
loss of cost-effective disposal options for solid waste generated by the facilities;
labor disputes or work stoppages by employees;
accidents and injuries;
reliability of our suppliers;
inability to comply with regulatory or permit requirements;
operational restrictions resulting from environmental permit limitations or governmental interventions;

construction delays and cost overruns;
disruptions in the delivery of electricity;
the availability of qualified personnel;
events occurring on third party systems that interconnect to and affect our system;
operator error; and
catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, sabotage acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences affecting our generating facilities, as well as our transmission and distribution systems.

The above risks could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures, and/or increased fuel and purchased power costs, any of which could have a material adverse effect on our financial condition, results of operations and cash flows. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action and/or reduced wholesale revenues.

Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.

The hazardous activities described above can also cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any such losses not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

In addition, operation of our owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels and likely result in decreased revenues and/or increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows.

We have constructed and placed into service FGD facilities and other equipment to better monitor environmental compliance at our base-load generating stations. If there is significant operational failure of such equipment at the generating stations, we may not be able to meet emission requirements at such generating stations. These events could result in a substantial increase in our operating costs. Depending on the degree, nature, extent, or willfulness of any failure to comply with environmental requirements, including those imposed by any consent decrees, such non-compliance could result in increased operating costs, the imposition of penalties or the shutting down of the affected generating stations, which could have a material adverse effect on our results of operations, financial condition and cash flows.

We are reliant upon the performance of co-owned generation stations which are operated by our co-owners for approximately 42% of our base-load generation.
Since approximately 42% of our base-load generation is derived from co-owned generation stations operated by our co-owners, poor operational performance by our co-owners, misalignment of co-owners’ interests with our own, or lack of control over costs (such as fuel costs) incurred at these stations could have an adverse effect on us. In addition, any sale of these co-owned generation stations by a co-owner to a third party could enhance the risk of a misalignment of interests, lack of cost control and other operational failures.


We may not always be able to recover our costs to deliver electricity to our retail customers. 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.
In Ohio, retail generation rates are no longer subject to cost-based regulation, while the transmission and distribution businesses are still regulated. Even though 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. On May 1, 2008, SB 221, an Ohio electric energy bill, was adopted that requires all Ohio distribution utilities to file either an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that measures a utility’s earnings to determine whether there have been significantly excessive earnings during a given calendar year. There can be no assurance 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 or permitted rates of return. Accordingly, the revenue DP&L receives may or may not match its expenses at any given time. Changes in or reinterpretations of, or the application unexpected by us of, the laws, rules, policies and procedures that set or govern electric rates, permitted rates of return, rate structures, ownership of generation assets, transition to or operation of a competitive bid structure to supply retail generation service to SSO customers, reliability initiatives, recovery of fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and the recovery of these and other costs on a full or timely basis through rates, power market prices, and the frequency and timing of rate increases, could have a material adverse effect on our results of operations, financial condition and cash flows.

On November 30, 2015, DP&L filed with the PUCO a distribution rate case to establish new distribution rates. And, on February 22, 2016, DP&L filed a new ESP with the PUCO, which was subsequently amended on October 11, 2016. There can be no assurance that any rate case or filing we make with the PUCO, including any settlement with parties to any case, will be approved as filed or on a timely basis by the PUCO, and if approval is not made on a timely basis or if the approval provides for terms that are more adverse than those submitted for approval, our consolidated results of operations, financial condition, cash flows, and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted. DP&L’s 2015 distribution rate case filing, current ESP, new ESP filing and certain other regulatory filings and matters, are further discussed in Item 1 - Business - Competition and Regulation, as well as in Note 3 – Regulatory Matters of Notes to DPL’s Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s Financial Statements.

Our increased costs due to renewable energy and energy efficiency requirements may not be fully recoverable in the future.
SB 221 contained targets relating to renewable energy, renewable energy, peak demand reduction and energy efficiency standards. SB 310 was passed in 2014 and modified the energy efficiency and renewable targets. It eliminated the advanced energy targets and the “in state” requirement for renewable energy. Annual targets for energy efficiency began in 2009 and require increasing energy reductions each year compared to a baseline energy usage, up to 22.3% by 2027. Peak demand reduction targets began in 2009 with increases in required percentages each year, up to 7.75% by 2020. The renewable energy standards have increased our costs and are expected to continue to increase (and could materially increase) these costs. DP&L is entitled to recover costs associated with its renewable energy compliance costs, as well as its energy efficiency and demand response programs. DP&L began recovering these costs in 2009. If in the future we are unable to timely or fully recover these costs, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these standards, monetary penalties could apply. These penalties are not permitted to be recovered from customers and significant penalties could have a material adverse effect on our results of operations, financial condition and cash flows. The demand reduction and energy efficiency standards by design result in reduced energy and demand that could adversely affect our results of operations, financial condition and cash flows.

The availability and cost of fuel and other commodities have experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from availability and price volatility, and substantially all of our electricity is generated by coal and a majority of our supply of coal comes from one supplier.
Our business is sensitive to changes in the price of coal, the primary fuel we use to produce electricity, and to changes in the prices of natural gas, and other fuels that are combusted in generation facilities. In addition, changes in the prices of steel, copper and other raw materials can have a significant impact on our costs. We also are dependent on purchased power, in part, to meet our seasonal planning reserve margins. Any changes in fuel

prices could affect the prices we charge, our operating costs and our competitive position with respect to our products and services.

Our approach is to hedge the fuel costs for our anticipated electric sales. However, we may not be able to hedge the entire exposure of our operations from fuel price volatility. In addition, market prices for power sales are volatile and not subject to control by any market participant. If market prices for power sales do not fully recover the costs of fuel, we would take steps to reduce our contract takes of fuel, but contractual requirements to take minimum amounts could cause an increase in fuel inventories and adverse financial effects. If in the future we are unable to timely or fully recover our fuel and purchased power costs from the market, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Approximately 93% of the energy we produced in 2016 was generated by coal. While we have a majority of our coal requirements for the three-year period ending December 31, 2019 under long-term contracts, the balance is yet to be purchased and will be purchased under a combination of long-term contracts, short-term contracts and on the spot market. Prices can be highly volatile in both the short-term market and on the spot market. The coal market has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic developments such as government-imposed direct costs and permitting issues that affect mining costs and supply availability, and the variable demand of retail customer load and the performance of our generation fleet, have an impact on our fuel procurement operations. In addition, pricing provisions in some of our coal contracts with terms of one year or more allow for price changes under certain circumstances.

Because of our substantial dependence on coal to meet customer demand for electricity, our business and operations could be materially adversely affected by unexpected price volatility in the coal market, price increases pursuant to the provisions of certain of our long-term coal contracts, and the continued regulatory and political scrutiny of coal. As discussed below, regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risk associated with climate change, could have a material adverse impact on our results of operations, financial condition and cash flows. Our dependence on coal also means that the output of our generation fleet can be greatly affected by the costs of other fuels combusted by generation facilities that compete with our coal-fired EGUs. Natural gas prices over the last several years have been relatively low and some gas-fired EGUs that previously were primarily used during periods of peak and intermediate electric demand are now running even during periods of relatively low demand. This has caused many coal-fired EGUs, including ours, to run fewer hours during these periods of base-load demand. If natural gas prices continue to remain low relative to their historic levels, it could have a material adverse effect on our results of operations, financial condition and cash flows.

In addition, all of our coal supply is currently mined by unaffiliated suppliers or third parties. Our goal is to carry a 25 - 35 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. In recent years, the coal industry has undergone significant restructuring as a result of debt restructurings, bankruptcy proceedings and other factors. Further restructuring may result in a failure of our suppliers to fulfill their contractual obligations or fewer suppliers and, consequently, increased dependency on any one supplier. Any significant disruption in the ability of our suppliers, particularly our most significant suppliers, to mine or deliver coal or other fuel, or any failure on the part of our suppliers to fulfill their contractual obligations could have a material adverse effect on our business. In the event of disruptions or failures, there can be no assurance that we would be able to purchase power or find another supplier of fuel on similarly favorable terms.

DP&L is a co-owner of certain generation facilities where it is a non-operating owner. DP&L does not procure or have control over the fuel for these facilities, but is responsible for its proportionate share of the cost of fuel procured at these facilities. Co-owner operated facilities do not always have realized fuel costs that are equal to our co-owners’ projections of such costs, and we are responsible for our proportionate share of any increase in actual fuel costs.

Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DP&L sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal price optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread,

adjusted for any quality differentials. Sales of coal are affected by a range of factors, including price volatility among the different coal basins and qualities of coal, variations in power demand and the market price of power compared to the cost to produce power. These factors could cause the amount and price of coal we sell to fluctuate, which could have a material adverse effect on our results of operations, financial condition and cash flows for any particular period.

DP&L may sell its excess emission allowances, including NOX and SO2 emission allowances, from time to time. Sales of any excess emission allowances are affected by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory for sale and changes to the regulatory environment, including the implementation of CSAPR. These factors could cause the amount and price of excess emission allowances DP&L sells to fluctuate, which could have a material adverse effect on DPL’s results of operations, financial condition and cash flows for any particular period. Although there has been overall reduced trading activity in the annual NOX and SO2 emission allowance trading markets in recent years, the adoption of regulations that regulate emissions or establish or modify emission allowance trading programs could affect the emission allowance trading markets and have a material effect on DP&L’s emission allowance sales.

Regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risks associated with climate change, could have a material adverse impact on our results of operations, financial condition and cash flows.
One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions, including by effectively putting a cost on such emissions to create financial incentives to reduce them. In 2016, DP&L emitted approximately 12 million tons of CO2 from its power plants. DP&L uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. DP&L’s CO2 emissions are calculated from actual fuel heat inputs and fuel type CO2 emission factors.

Any existing or future international, federal, state or regional legislation or regulation of GHG emissions could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors including, among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which market-based compliance options are available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. As a result of these factors, our cost of compliance could be substantial and could have a material adverse impact on our results of operations, financial condition and cash flows. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations.

Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our EGUs and our support facilities. Variations in weather conditions, primarily temperature and humidity, would also be expected to affect the energy needs of customers. A decrease in energy consumption could decrease our revenues. In addition, while revenues would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired EGUs. If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our results of operations, financial condition and cash flows.

In addition to the rules already in effect, regulatory initiatives regarding GHG emissions may be implemented in the future, although at this time we cannot predict if, how, or to what extent such initiatives would affect us. Generally, costs to comply with any regulations implemented to reduce GHG emissions, including those already promulgated, are part of the costs of providing electricity to our customers. While we might seek recovery for such costs, there can be no assurance that the PUCO will approve such requests or that we will be able to recover such costs.

Finally, concerns over GHG emissions and their effect on the environment have led and could lead further to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial condition and cash flows. See Item 1 - Business - Environmental Matters for addition information of environmental matters impacting us, including those relating to regulation of GHG emissions.

We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations, may expose us to environmental liabilities or make continued operation of certain generating units unprofitable.
We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of ash and other materials, some of which may be defined as hazardous materials; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. We could also become subject to additional environmental laws and regulations and other requirements in the future (such as reductions in mercury and other hazardous air pollutants, SO3 and further reductions in GHG emissions as discussed in more detail in the previous risk factor) and limits on water use and discharge. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits inspections and other governmental authorizations. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and other government authorizations required to operate our business, then our operations could be prevented, delayed or subject to additional costs. A violation of environmental laws, regulations, permits or other requirements can result in substantial fines, penalties, other sanctions, permit revocation, facility shutdowns, the imposition of stricter environmental standards and controls or other injunctive measures affecting operating assets. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. With respect to our largest EGU, the Stuart generating station, we are also subject to continuing compliance requirements related to NOX, SO2 and particulate matter emissions under DP&L’s consent decree with the Sierra Club. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. DP&L owns a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, DP&L is responsible for its pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but has limited control over the compliance measures taken by our co-owners. Under certain environmental laws, we could also be held responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held liable for human exposure to such hazardous substances or for other environmental damage. From time to time we are subject to enforcement and litigation actions for claims of noncompliance with environmental laws and regulations. DP&L cannot assure that it will be successful in defending against any claim of noncompliance. Any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows. For example, the amount of capital expenditures required to comply with environmental laws or regulations could be impacted by the outcome of the USEPA’s NOVs described in this Annual Report on Form 10-K. See Item 1 - Business - Environmental Matters for a more comprehensive discussion of these and other environmental matters impacting us.

The use of non-derivative and derivative instruments in the normal course of business could result in losses that could negatively impact our results of operations, financial position and cash flows.
From time to time, we use non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks. These trades are affected by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts, a counterparty failing to perform, or the underlying transactions which the instruments are

intended to hedge failing to materialize, which could result in a material adverse effect on our results of operations, financial condition and cash flows.

The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.
In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.

Our business is sensitive to weather and seasonal variations.
Weather conditions significantly affect the demand for electric power, and accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our operating revenues and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Our current plan to separate our generation business into a separate legal entity from our distribution and transmission business is subject to PUCO and FERC approval.
The anticipated legal separation of DP&L’s generation business from its distribution and transmission business is subject to PUCO and FERC approval, If any such approvals were not obtained, rescinded or otherwise modified, our plans and forecasts to separate could be adversely impacted which could have a material effect on our results of operations.

Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.
On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM, a regional transmission organization. The price at which we can sell our generation capacity and energy is now 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 business rules. While we can continue to make bilateral transactions to sell our generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM. To the extent we sell electricity into the power markets on a contractual basis, we are not guaranteed any rate of return on our capital investments through mandated rates. The results of the PJM capacity auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources and other factors. Auction prices could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows. We cannot predict the outcome of future auctions, but low auction prices could have a material adverse effect on our results of operations, financial condition and cash flows.

The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, PJM has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial effect on us. We also incur fees and costs to participate in PJM.

SB 221 includes a provision that allows electric utilities to seek and obtain recovery of RTO-related charges. Therefore, non-market based costs are being recovered from all retail customers through the TCRR-N. If in the future, however, we are unable to recover all of these costs in a timely manner this could have a material adverse effect on our results of operations, financial condition and cash flows.

As members of PJM, DP&L and AES Ohio Generation are also subject to certain additional risks including those associated with the allocation of losses caused by unreimbursed defaults of other participants in PJM markets among PJM members and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L and AES Ohio Generation. These amounts could be significant and have a material adverse effect on our results of operations, financial condition and cash flows.

Costs associated with new transmission projects could have a material adverse effect on our results of operations, financial condition and cash flows.
Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. Over the last several years, however, some of the costs of constructing new large transmission facilities have been “socialized” across PJM without a direct relationship between the costs assigned to and benefits received by particular PJM members. To date, the additional costs charged to DP&L for new large transmission approved projects have not been material. Over time, as more new transmission projects are constructed and if the allocation method is not changed, the annual costs could become material. DP&L is recovering the Ohio retail jurisdictional share of these allocated costs from its retail customers through the TCRR-N rider. To the extent that any costs in the future are material and we are unable to recover them from our customers, it could have a material adverse effect on our results of operation, financial condition and cash flows.

If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.
As an owner of a bulk power transmission system, DP&L is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. In addition, DP&L is subject to Ohio reliability standards and targets. Compliance with reliability standards may subject us to higher operating costs or increased capital expenditures. Although we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCO will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which could have a material adverse effect on our results of operations, financial condition and cash flows.

We rely on access to the financial markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms, or at all, and cause increases in our interest expense.
From time to time we rely on access to the capital and credit markets as a source of liquidity for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time and the ability of corporations to raise capital can be negatively affected. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. It is possible that our ability to raise capital on favorable terms, or at all, could be adversely affected by future market conditions, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing and other general economic and business conditions. It may also depend on the performance of credit counterparties and financial institutions with which we do business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability. See Note 8 – Debt of Notes to DPL’s Consolidated Financial Statements and Note 7 – Debt of Notes to DP&L’s Financial Statements for information regarding indebtedness. See also Item 7A - Quantitative and Qualitative Disclosure about Market Riskfor information related to market risks.


Wholesale power marketing activities may add volatility to earnings.
We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the PJM day-ahead and real-time markets. As part of these strategies, we may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. The earnings from our wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity, beyond that needed to meet firm service requirements. In order to reduce the risk of volatility in earnings from wholesale marketing activities, we may at times enter into forward contracts to hedge such risk. If our hedging procedures do not operate as planned we may experience losses. In addition, the introduction of additional renewable energy, demand response or other energy supply into the PJM market could have the effect of reducing the demand for wholesale energy from other sources. This additional generation could have the impact of reducing market prices for energy and could reduce our opportunity to sell coal-fired and gas generation into the PJM market, thereby reducing our wholesale sales. Additionally, decreases in natural gas prices in the U.S. have the impact of reducing market prices for electricity, which can reduce our ability to sell excess generation on the wholesale market, as well as reduce our profit margin on wholesale sales.

Under the PJM Capacity Performance program, we could be subject to substantial changes in capacity income and/or penalties.
As the owner of generation that is a “capacity resource” within PJM, DP&L is subject to mandatory requirements to participate in PJM markets. The Capacity Performance program offers the potential for higher capacity prices paired with higher penalties for non-performance during times of high electricity demand. Any such penalties could have a material adverse effect on our results of operations, financial condition and cash flows. See Item 1 - Business - Competition and Regulation for additional information about the PJM program.

Our transmission and distribution system is subject to reliability and capacity risks.
The ongoing reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, fires and/or explosions, plant outages, labor disputes, operator error or inoperability of key infrastructure internal or external to us. The failure of our transmission and distribution system to fully deliver the energy demanded by customers could have a material adverse effect on our results of operations, financial condition and cash flows, and if such failures occur frequently and/or for extended periods of time, could result in adverse regulatory action. In addition, the advent and quick adaptation of new products and services that require increased levels of electrical energy cannot be predicted and could result in insufficient transmission and distribution system capacity.

Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties, which may adversely affect our results of operations, financial condition and cash flows.
Our business, results of operations, financial condition and cash flows have been and will continue to be affected by general economic conditions. Slowing global economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in the normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic conditions improve. Some of our suppliers, customers, and other counterparties, and others with whom we transact business may also experience financial difficulties, which may impact their ability to fulfill their obligations to us. For example, our counterparties on forward purchase contracts and financial institutions involved in our credit facility may become unable to fulfill their contractual obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, the projected economic growth and total employment in DP&L’s service territory are important to the realization of our forecasts for annual energy sales.


The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility, and a material change in market interest rates could adversely affect our results of operations, financial condition and cash flows.
As of December 31, 2016, the carrying value of DPL's debt was $1,858.4 million and the carrying value of DP&L's debt was $749.4 million. Of DP&L's indebtedness, there was $745.0 million of First Mortgage Bonds, tax-exempt bonds and a term loan outstanding as of December 31, 2016, which are each secured by the pledge of substantially all of the assets of DP&L under the terms of DP&L’s First & Refunding Mortgage. This level of indebtedness and related security could have important consequences, including the following:

increasing our vulnerability to general adverse economic and industry conditions;
requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
limiting, along with the financial and other restrictive covenants in our indebtedness, our ability to borrow additional funds, as needed.

If DP&L issues additional debt in the future, we will be subject to the terms of such debt agreements and be required to obtain regulatory approvals. To the extent we increase our leverage, the risks described above would also increase. Further, actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. For a further discussion of our outstanding debt obligations, see Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition, Liquidity and Capital Requirements and Note 8 – Debt of Notes to DPL’s Consolidated Financial Statements and Note 7 – Debt of Notes to DP&L’s Financial Statements.

DP&L has variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, rating agencies issue ratings on our credit and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Credit ratings also govern the collateral provisions of certain of our contracts. If the rating agencies were to downgrade our credit ratings further, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.

Economic conditions relating to the asset performance and interest rates of our pension and postemployment benefit plans could materially and adversely impact our results of operations, financial condition and cash flows.
Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of our pension and postemployment benefit plan assets compared to obligations under our pension and postemployment benefit plans. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postemployment benefit plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postemployment benefit plan assets will increase the funding requirements under our pension and postemployment benefit plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our pension and postemployment benefit plans’ assets compared to obligations under the pension and postemployment benefit plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment

benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.

Counterparties providing materials or services may fail to perform their obligations, which could harm our results of operations, financial condition and cash flows.
We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components (such as limestone for our FGD equipment), for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.

Further, from time to time our construction program may call for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, improvements to generation, transmission and distribution facilities, as well as other initiatives. As a result, we may engage contractors and enter into agreements to acquire necessary materials and/or obtain required construction related services. In addition, some contracts may provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause construction delays. It could also subject us to enforcement action by regulatory authorities to the extent that such a contractor failure resulted in a failure by DP&L to comply with requirements or expectations, particularly with regard to the cost of the project. As a result of these events, we might incur losses or delays in completing construction.

Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure or incorrect payment processing.
Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP in the United States of America, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.

New accounting standards or changes to existing accounting standards could materially affect how we report our results of operations, financial condition and cash flows.
Our Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially affect how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our Consolidated Financial Statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.


We are subject to extensive laws and local, state and federal regulation, as well as litigation and other proceedings that could affect our operations and costs.
As an electric utility, we are subject to extensive regulation at both the federal and state level. For example, at the federal level, we are regulated by the FERC and the NERC and, at the state level, we are regulated by the PUCO. The regulatory power of the PUCO over DP&L is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Ohio. We are subject to regulation by the PUCO as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of securities and incurrence of debt, the acquisition and sale of some public utility properties or securities and certain other matters. As a result of the Energy Policy Act of 2005 and subsequent legislation affecting the electric utility industry, we have been required to comply with rules and regulations in areas including mandatory reliability standards, cybersecurity, transmission expansion and energy efficiency. We are currently unable to predict the long-term impact, if any, to our results of operations, financial condition and cash flows as a result of these rules and regulations. Complying with the regulatory environment to which we are subject requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business that could have a material adverse effect on our results of operations, financial condition and cash flows.

We may be subject to material litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time which may require us to expend significant funds to address. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition and cash flows. Asbestos and other regulated substances are, and may continue to be, present at our facilities. We have been named as a defendant in asbestos litigation, which at this time is not expected to be material to us. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. See Item 1 - Business - Competition and Regulation, Item 1 - Business - Environmental Matters, and Item 3 - Legal Proceedings for a summary of significant regulatory matters and legal proceedings involving us.

If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.
One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We may not be able to successfully train new personnel as current workers with significant knowledge and expertise retire. We also may be unable to staff our business with qualified personnel in the event of significant absenteeism related to a pandemic illness. We also have policies and procedures in place to mitigate excessive risk-taking by employees since excessive risk-taking by our employees to achieve performance targets could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements with employees who are members of a union. Over half of our employees are represented by a collective bargaining agreement that is in effect until October 31, 2017. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreement or at the expiration of the collective bargaining agreement before a new agreement is negotiated. Work stoppages by, or poor relations or ineffective negotiations with, our employees or other workforce issues could have a material adverse effect on our results of operations, financial condition and cash flows.

Potential security breaches (including cybersecurity breaches) and terrorism risks could adversely affect our businesses.
We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation stations, fuel storage facilities and transmission and distribution facilities.

We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war. We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely way to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenues and increases in costs that could adversely affect our results of operations, cash flows and financial condition.

In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information. If our or our third party vendors’ systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.

To help mitigate these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.

DPL is a holding company and parent of DP&L and other subsidiaries. DPL’s cash flow is dependent on the operating cash flows of DP&L and its other subsidiaries and their ability to pay cash to DPL.
DPL is a holding company with no material assets other than the common stock of its subsidiaries, and accordingly all cash is generated by the operating activities of its subsidiaries, principally DP&L. As such, DPL’s cash flow is largely dependent on the operating cash flows of DP&L and its ability to pay cash to DPL. See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity for a discussion of these restrictions. See Note 8 – Debt of Notes to DPL’s Consolidated Financial Statements and Note 7 – Debt of Notes to DP&L’s Financial Statements for information regarding indebtedness. In addition, DP&L is regulated by the PUCO, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The PUCO could impose additional restrictions on the ability of DP&L to distribute, loan or advance cash to DPL pursuant to these broad powers. 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. See Note 11 – Equity of Notes to DPL's Consolidated Financial Statements and Note 10 – Equity of Notes to DP&L's Financial Statements for information related to restrictions on DP&L's equity and its ability to declare and pay dividends to DPL. After the fixed-asset impairments recorded during the second and fourth quarters of 2016 and as of December 31, 2016, DP&L's equity ratio was 32% and its retained earnings balance was negative. While we do not expect any of the foregoing to significantly affect DP&L’s ability to pay funds to DPL in the near future, a significant limitation on DP&L’s ability to pay dividends or loan or advance funds to DPL would have a material adverse effect on DPL’s results of operations, financial condition and cash flows. In addition, as a result of any non-compliance with PUCO requirements, the PUCO could impose additional restrictions on DP&L operations that could have a material adverse effect in DPL's and DP&L's results of operations, financial condition and cash flows.

Our ownership by AES subjects us to potential risks that are beyond our control.
All of DP&L’s common stock is owned by DPL, and DPL is an indirectly wholly owned subsidiary of AES. Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in DPL’s or DP&L’s credit ratings being downgraded.

Impairment of long-lived assets would negatively affect our consolidated results of operations and net worth.
Long-lived assets are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present. The recoverability assessment of long-lived assets requires making estimates and assumptions to determine fair value, as described above. See Note 15 – Fixed-asset Impairment of Notes to DPL’s Consolidated Financial Statements and Note 14 – Fixed-asset Impairment of Notes to DP&L's Financial Statements for more information on the impairment of fixed assets.

Item 1B – Unresolved Staff Comments
None.

Item 2 – Properties
Information relating to our properties is contained in Item 1 – Business – Electric Operations and Fuel Supply and Note 4 – Property, Plant and Equipment of Notes to DPL's Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L's Financial Statements.

Substantially all property and stations of DP&L are subject to the lien of the First and Refunding Mortgage.

Item 3 – Legal Proceedings

DPL and DP&L are involved in certain claims, suits and legal proceedings in the normal course of business. DPL and DP&L have accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. DPL and DP&L believe, based upon information they currently possess and taking into account established reserves for estimated liabilities and insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on their financial statements. It is reasonably possible, however, that some matters could be decided unfavorably and could require DPL or DP&L to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2016.

The following additional information is incorporated by reference into this Item: information about the legal proceedings contained in Item 1 - Business - Competition and Regulation and Item 1 - Business - Environmental Matters.

Item 4 – Mine Safety Disclosures
Not applicable.

PART II
Item 5 – Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
All of the outstanding common stock of DPL is owned indirectly by AES and directly by an AES wholly-owned subsidiary. As a result, our stock is not listed for trading on any stock exchange. DP&L’s common stock is held solely by DPL and, as a result, is not listed for trading on any stock exchange.

Dividends
During the years ended December 31, 2016, 2015 and 2014, DPL paid no dividends to AES. DP&L declares and pays dividends on its common shares to its parent DPL from time to time as declared by the DP&L board. Dividends on common shares in the amount of $70.0 million, $50.0 million and $159.0 million were declared and paid in the years ended December 31, 2016, 2015 and 2014, respectively. DP&L declared and paid dividends on preferred shares of $0.7 million in the year ended December 31, 2016 and $0.9 million in each of the years ended December 31, 2015 and 2014.

As of December 31, 2016, DPL’s leverage ratio was at 1.45 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2016, DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

DPL’s secured revolving credit agreement, secured term loan and senior unsecured notes due 2019 include provisions substantially similar to DPL's Articles of Incorporation. As a result, as of December 31, 2016, DPL was also prohibited under each of these documents from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

DP&L’s Amended Articles of Incorporation contain provisions limiting the payment of cash dividends on any of its common stock while any preferred stock of DP&L is outstanding. See Note 10 – Equity of Notes to DP&L's Consolidated Financial Statements. On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L redeemed all of its issued and outstanding preferred stock. See Note 11 – Equity of Notes to DPL's Consolidated Financial Statements for more information.

Item 6 – Selected Financial Data
The following table presents our selected consolidated financial data which should be read in conjunction with our audited Consolidated Financial Statements and the related Notes thereto and Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations. The “Results of Operations” discussion in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations addresses significant fluctuations in operating data. DPL’s common stock is wholly-owned by an indirect subsidiary of AES and therefore DPL does not report earnings or dividends on a per-share basis. Other information that management believes is important in understanding trends in our business is also included in this table. The information for DPL for 2012 is not comparable to the information for 2016, 2015, 2014 or 2013 as 2012 has not been adjusted to reflect the sale of DPLER and its reclassification as a discontinued operation.
DPL
$ in millions except per share amounts or as indicated Year ended December 31, 2016 Year ended December 31, 2015 Year ended December 31, 2014 Year ended December 31, 2013 Year ended December 31, 2012
Total electric sales (millions of kWh) 16,757
 14,738
 14,695
 15,702
 16,454
Statements of Operations Data          
Revenues $1,427.3
 $1,612.8
 $1,716.5
 $1,579.0
 $1,668.4
Goodwill impairment (a)
 $—
 $317.0
 $—
 $306.3
 $1,817.2
Fixed-asset impairment (b)
 $859.0
 $—
 $11.5
 $26.2
 $—
Operating income / (loss) $(683.9) $(109.9) $230.7
 $(77.4) $(1,559.4)
Net income / (loss) from continuing operations $(514.5) $(251.4) $57.2
 $(225.6) $(1,729.8)
Net income / (loss) from discontinued operations, net of tax $29.3
 $12.4
 $(131.8) $3.6
 $—
Net income / (loss) $(485.2) $(239.0) $(74.6) $(222.0) $(1,729.8)
Construction additions $140.0
 $132.0
 $116.0
 $114.0
 $180.0
           
Balance sheet data (end of period):        
Total assets $2,419.2
 $3,324.7
 $3,559.1
 $3,699.3
 $4,231.4
Long-term debt (c)
 $1,828.7
 $1,420.5
 $2,120.9
 $2,262.0
 $2,009.1
Redeemable preferred stock of subsidiary $—
 $18.4
 $18.4
 $18.4
 $18.4
Total common shareholder's equity $(587.6) $(80.6) $148.2
 $239.5
 $426.8

DP&L
$ in millions except per share amounts or as indicated Year ended December 31, 2016 Year ended December 31, 2015 Year ended December 31, 2014 Year ended December 31, 2013 Year ended December 31, 2012
Total electric sales (millions of kWh) 16,158
 16,424
 18,613
 19,423
 15,606
Statements of Operations Data          
Revenues $1,365.9
 $1,552.3
 $1,668.3
 $1,551.5
 $1,531.8
Fixed-asset impairment (b)
 $1,353.5
 $—
 $—
 $86.0
 $80.8
Operating income $(1,170.1) $177.8
 $188.8
 $139.9
 $185.0
Income / (loss) attributable to common stock $(773.4) $105.5
 $114.1
 $82.7
 $90.3
Construction additions $119.0
 $124.0
 $112.0
 $111.0
 $177.0
           
Balance sheet data (end of period):          
Total assets $2,035.1
 $3,359.6
 $3,328.8
 $3,300.4
 $3,457.5
Long-term debt (c)
 $744.7
 $313.6
 $868.2
 $865.3
 $326.2
Redeemable preferred stock $—
 $22.9
 $22.9
 $22.9
 $22.9
Total common shareholder's equity $362.3
 $1,212.7
 $1,143.4
 $1,204.0
 $1,299.1
           
Number of shareholders - preferred stock —
 180
 186
 196
 209

(a)Goodwill impairments of $317.0 million, $306.3 million and $1,817.2 million were recorded in 2015, 2013 and 2012, respectively. The goodwill impairment of $135.8 million in 2014 related to DPLER has been reclassified to discontinued operations.
(b)
For DPL, fixed-asset impairments of $859.0 million ($558.3 million net of tax), $11.5 million ($7.5 million net of tax) and $26.2 million ($17.0 million net of tax) were recorded in 2016, 2014 and 2013, respectively. For DP&L, fixed-asset impairments of $1,353.5 million ($879.8 million net of tax), $86.0 million ($55.9 million net of tax) and $80.8 million ($51.8 million net of tax) were recorded in 2016, 2013 and 2012, respectively.
(c)Excludes current maturities of long-term debt.

Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with DPL’s audited Consolidated Financial Statements and the related Notes thereto and DP&L’s audited Financial Statements and the related Notes thereto included in Item 8 – Financial Statements and Supplementary Data of this Form 10-K. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. See “Forward-Looking Statements” at the beginning of this Form 10-K and Item 1A – Risk Factors. For a list of certain abbreviations or acronyms in this discussion, see Glossary of Terms at the beginning of this Form 10-K.

Key topics in Management's Discussion and Analysis

Our discussion covers the following:
Review of Results of Operations
◦DPL
▪
DPL - T&D Segment
▪
DPL - Generation Segment
◦DP&L
▪
DP&L - T&D Segment
▪
DP&L - Generation Segment
Key Trends and Uncertainties
Capital Resources and Liquidity
Critical Accounting Estimates


RESULTS OF OPERATIONS – DPL Inc.

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.

Statement of Operations Highlights – DPL
  Years ended December 31,
$ in millions 2016 2015 2014
Revenues:      
Retail $738.7
 $785.2
 $832.5
Wholesale 477.7
 598.2
 685.0
RTO revenue 62.4
 70.1
 81.9
RTO capacity revenues 137.4
 150.4
 107.9
Other revenues 11.1
 8.8
 9.2
Mark-to-market gains —
 0.1
 —
Total revenues 1,427.3
 1,612.8
 1,716.5
Cost of revenues:      
Cost of Fuel:      
Fuel 275.4
 263.1
 305.4
Gains from sale of coal (6.6) (3.0) (1.3)
Mark-to-market losses / (gains) —
 (0.3) 0.4
Net fuel cost 268.8
 259.8
 304.5
Purchased power:      
Purchased power 322.0
 336.1
 323.7
RTO charges 78.4
 97.9
 154.2
RTO capacity charges 21.3
 122.5
 107.5
Mark-to-market losses / (gains) (4.3) 6.1
 2.5
Net purchased power 417.4
 562.6
 587.9
       
Total cost of revenues 686.2
 822.4
 892.4
Gross margin $741.1
 $790.4
 $824.1
Operating expenses:      
Operation and maintenance 348.1
 361.3
 362.4
Depreciation and amortization 132.3
 134.6
 135.6
General taxes 85.7
 87.0
 87.8
Goodwill impairment (Note 7) —
 317.0
 —
Fixed-asset impairment (Note 15) 859.0
 —
 11.5
Other (0.1) 0.4
 (3.9)
Total operating expenses 1,425.0
 900.3
 593.4
       
Operating income / (loss) (683.9) (109.9) 230.7
Other expense, net      
Investment income 0.4
 0.2
 0.9
Interest expense (106.1) (118.3) (126.6)
Charge for early redemption of debt (3.1) (2.1) (30.9)
Other deductions (0.6) (1.3) (1.5)
Other expense, net (109.4) (121.5) (158.1)
       
Income / (loss) from continuing operations before income tax (a) $(793.3) $(231.4) $72.6

(a)For purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. 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 affected by the number of heating and cooling degree days occurring during a year. Cooling degree days typically have a more significant effect than heating degree days since some residential customers do not use electricity to heat their homes.

Degree days
  Years ended December 31,

 2016 2015 2014
Heating degree days (a)
 5,034 5,163 5,950
Cooling degree days (a)
 1,213 1,060 977

(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 have historically utilized our internal generating capacity to supply the needs of our retail customers within the DP&L service territory first, increases in on-system retail demand may have decreased the volume of internal generation available to be sold in the wholesale market and vice versa. Beginning in 2016, DP&L retail demand is entirely sourced through a competitive auction. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors affecting our wholesale sales volume each hour of the year include: wholesale market prices; retail demand throughout the entire wholesale market area; our stations’ and other utility stations’ 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 or when margin opportunities exist between the wholesale sales and power purchase prices.

The following table provides a summary of changes in revenues from prior periods:
$ in millions 2016 vs. 2015 2015 vs. 2014
Retail    
Rate $(68.7) $(28.7)
Volume 21.0
 (13.0)
Other 1.2
 (5.6)
Total retail change (46.5) (47.3)
Wholesale    
Rate (124.4) 4.1
Volume 3.9
 (90.9)
Total wholesale change (120.5) (86.8)
RTO revenues and RTO capacity revenues    
RTO revenues and RTO capacity revenues (20.7) 30.7
Other    
Other 2.2
 (0.3)
Total revenue changes $(185.5) $(103.7)

During the year ended December 31, 2016, Revenues decreased $185.5 million to $1,427.3 million from $1,612.8 million in the same period of the prior year. This decrease was primarily the result of lower average retail and wholesale rates and lower RTO and RTO capacity revenues, partially offset by higher retail and wholesale volumes.
Retail revenues decreased $46.5 million primarily due to an unfavorable $68.7 million retail rate variance and a favorable $21.0 million retail volume variance. The unfavorable rate variance was due to lower average DP&L retail rates, primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, was lower than the non-auction SSO rate. The decrease was also due to the recovery of deferred storm costs in 2015 and the reversion back to ESP 1 rates in September of 2016, partially offset by $20.1 million of revenue associated with energy efficiency programs recorded in 2016. This decrease in rate was

partially offset by a volume increase due to warmer summer weather in 2016 as cooling degree days increased by 153 along with increased sales to commercial and industrial customers, partially offset by milder winter weather in the first quarter of 2016 as heating degree days decreased by 129.
Wholesale revenues decreased $120.5 million primarily as a result of an unfavorable $124.4 million wholesale rate variance and a favorable $3.9 million wholesale volume variance. The unfavorable price variance of $124.4 million was primarily due to lower market prices in 2016 and higher average prices on sales to DPLER in 2015, as DP&L previously had full requirements sales to DPLER in 2015. This price decrease was partially offset by a favorable wholesale volume variance as DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015. In addition, there was a 4.5% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the prior year, partially offset by a decrease in volume due to the contract termination with DPLER. As noted above, DP&L previously had full requirements sales to DPLER in 2015. These sales were previously eliminated in consolidation prior to DPLER being accounted for as a discontinued operation.
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 PJM capacity payments, decreased $20.7 million compared to the prior year. This decrease was the result of a $7.7 million decrease in RTO transmission and congestion revenue, as 2015 congestion revenue charges were higher due to milder winter weather in 2016 than 2015. There was also a $13.0 million decrease in revenue realized from the PJM capacity auction in 2016 due to lower capacity cleared and lower prices in both the CP and RPM auctions. The capacity price that became effective in June of 2016 was $134/MW-day, compared to $136/MW-day in June 2015.

During the year ended December 31, 2015, Revenues decreased $103.7 million to $1,612.8 million from $1,716.5 million in the same period of the prior year. This decrease was primarily the result lower retail and wholesale volumes and lower average retail rates, partially offset by higher wholesale rates and increased RTO capacity revenues.
Retail revenues decreased $47.3 million primarily due to lower retail prices driven by decreased retail revenue for SSO customers as the competitive auction rate, which represented 60% of DP&L SSO load in 2015 as compared to 10% in 2014, is lower than our non-auction SSO rate, a decrease in the USF program recovery rate in 2015, and higher recovery of transmission costs in the prior year. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015. Sales volume also decreased due to milder winter weather in 2015. The above resulted in an unfavorable $28.7 million retail rate variance and an unfavorable $13.0 million retail volume variance. In addition, there was an unfavorable other miscellaneous variance of $5.6 million.
Wholesale revenues decreased $86.8 million as a result of an unfavorable $90.9 million wholesale volume variance and a favorable $4.1 million wholesale rate variance. Although DP&L had excess generation available to be sold in the wholesale market in 2015 resulting from 60% of its SSO load being served through the competitive bid process compared to 10% during 2014, there was also a 17% decrease in net generation from DP&L's co-owned and operated plants due to the 2014 sale of East Bend, the closing of Beckjord and increased outages. DPL also had decreased full requirements sales to DPLER, as a result of the sale of MC Squared and decreased customers at DPLER in 2015 compared to 2014. These sales were previously eliminated in consolidation prior to DPLER becoming a discontinued operation. The price increase of $4.1 million was due to higher average prices on sales to DPLER, partially offset by lower market prices.
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, increased $30.7 million compared to the prior year. This increase was primarily the result of a $42.5 million increase in revenue realized from the PJM capacity auction. The capacity price that became effective in June 2015 was $136/MW-day compared to $126/MW-day in June 2014. This increase was offset by an $11.8 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.


DPL – Cost of Revenues
During the year ended December 31, 2016, Total cost of revenues decreased $136.2 million compared to the prior year. This decrease was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $9.0 million compared to the prior year primarily due to a 7.2% increase in internal generation, partially offset by a 2.4% decrease in average fuel cost per MWh.
Net purchased power decreased $145.2 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $14.1 million primarily due to a $55.4 million volume decrease as DP&L no longer purchases power to source DPLER customers due to the sale of DPLER on January 1, 2016. This volume decrease was partially offset by increased purchases as DP&L now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DPL purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's. The decrease in volume was also offset by an unfavorable price variance of $41.3 million driven by higher prices in the competitive bid process.
◦
RTO charges decreased $19.5 million primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.
◦
RTO capacity charges decreased $101.2 million primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and, additionally, from the fact that DP&L did not provide power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.
◦Mark-to-market gains increased $10.4 million due to less significant decreases in power prices in 2016, resulting in gains on derivative forward power purchase contracts.

During the year ended December 31, 2015, Total cost of revenues decreased $70.0 million compared to the prior year. This decrease was a result of:
Net fuel costs decreased $44.7 million compared to the prior year, primarily due to a 16% decrease in internal generation as a result of increased outages and plant closures or sales, partially offset by a 2.4% increase in average fuel cost per MWh.
Net purchased power decreased $25.3 million compared to the prior year. This decrease was driven by the following factors:
◦Purchased power increased $12.4 million primarily due to a $23.9 million increase as a result of a 6.5% increase in average purchased power price, and also due to increased purchases for our SSO load through the competitive bid process. These increases were partially offset by an $11.5 million volume decrease driven by decreased power purchased to source DPLER customers throughout 2015 due to the sale of MC Squared along with customer switching. The price increase above also includes a partial offset resulting from a $10 million regulatory deferral of OVEC costs that are probable for future recovery. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.
◦
RTO charges decreased $56.3 million as a result of higher transmission and congestion charges incurred in 2014 as well as decreased load obligations as a result of increased SSO sales being sourced through the competitive auction. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

◦RTO capacity charges increased $15.0 million, driven by a $7.3 million PJM penalty associated with low plant availability in 2015 compared to an approximate $2.4 million penalty recorded in 2014 and higher RTO capacity prices, partially offset by decreased load obligations for retail customers in 2015. As noted above, RTO capacity prices are set by an annual auction.
◦Mark-to-market losses increased $3.6 million.

DPL - Operation and Maintenance
During the year ended December 31, 2016, Operation and Maintenance expense decreased $13.2 million compared to the prior year. This decrease was a result of:
$ in millions 2016 vs. 2015
Decrease in deferred storm costs as they were recognized in 2015 due to their recovery through customer rates (a)
 $(17.5)
Decrease in generating facilities operating and maintenance expenses (13.0)
Decrease in expenses due to the reversal of the Economic Development Fund, resulting from the withdrawal of ESP 2 (3.0)
Decrease in group insurance, associated with the participation in the AES self-insurance plan, and long-term disability expenses (2.5)
Increase in alternative energy and energy efficiency programs(a)
 13.2
Increase in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
 6.2
Increase in retirement benefits costs 1.8
Increase in property insurance 1.5
Other, net 0.1
Net change in operation and maintenance expense $(13.2)

(a)There is corresponding revenue associated with this program resulting in no impact to Net income.

During the year ended December 31, 2015, Operation and Maintenance expense decreased $1.1 million compared to the prior year. This decrease was a result of:
$ in millions2015 vs. 2014
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)

$(20.1)
Increase in deferred storm costs as they were recognized in 2015 due to their recovery through customer rates (a)

17.5
Increase in alternative energy and energy efficiency programs (a)
3.9
Other, net(2.4)
Net change in operation and maintenance expense$(1.1)

(a)There is corresponding revenue associated with this program resulting in no impact to Net income.

DPL – Depreciation and Amortization
During the year ended December 31, 2016, Depreciation and amortization expense decreased $2.3 million compared to the prior year. The decrease was primarily a result of the fixed asset impairment in Q2 of 2016, which reduced depreciation expense due to the lower asset values.

During the year ended December 31, 2015, Depreciation and amortization expense decreased $1.0 million compared to the prior year. The decrease is primarily due to the sale of East Bend and the retirement of Beckjord, partially offset by increased depreciation associated with increased ARO assets and net plant additions.

DPL – Goodwill Impairment
During the year ended December 31, 2016, DPL did not record any goodwill impairment.

During the year ended December 31, 2015, DPL recorded an impairment of goodwill of $317.0 million, which was a full impairment of the remaining goodwill balance. The goodwill impairment test indicated that the fair value of the DP&L Reporting Unit was less than its carrying amount, primarily due to a decrease in dark spreads that were

driven by decreases in forward power prices, and lower revenues from the new CP product. See Note 7 – Goodwill of Notes to DPL’s Consolidated Financial Statements.

The goodwill impairment in 2014 was reclassified to Discontinued operations. See Note 16 – Discontinued Operations of Notes to DPL’s Consolidated Financial Statements.

DPL – Fixed Asset Impairment
During the year ended December 31, 2016, DPL recorded an impairment of fixed assets of $859.0 million. In the second quarter of 2016, DPL recorded a $235.5 million fixed-asset impairment as DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Killen and certain DP&L peaking generating facilities were not recoverable. In the fourth quarter of 2016, DPL recorded an additional $623.5 million fixed asset impairment as DP&L performed a long-lived asset impairment analysis for the Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups, as well as the Hutchings gas-fired peaking plant asset group and determined that their carrying amounts were not recoverable.

During the year ended December 31, 2015, DPL did not record a fixed-asset impairment, compared to an impairment of fixed assets of $11.5 million during the year ended December 31, 2014 related to DP&L's East Bend facility, which was sold in 2014.

For more information on these impairments, see Note 15 – Fixed-asset Impairment of Notes to DPL's Consolidated financial Statements.

DPL – Interest Expense
During the year ended December 31, 2016, Interest expense decreased $12.2 million compared to the prior year due primarily to debt repayments at DPL and DP&L, as well as a $3.8 million decrease in carrying costs primarily related to the recovery of deferred storm costs in 2015.

During the year ended December 31, 2015, Interest expense decreased $8.3 million compared to the prior year due primarily to a reduction of debt at DP&L and DPL, as well as decreased interest rates on DP&L’s senior secured tax-exempt First Mortgage Bonds, partially offset by increased carrying costs on regulatory assets.

DPL – Charge for Early Redemption of Debt
During the year ended December 31, 2016, Charge for early redemption of debt increased $1.0 million primarily due to the February 2016 make-whole premium of $2.4 million associated with the early retirement of $73.0 million of the 6.5% Senior Notes due in 2016.

During the year ended December 31, 2015, Charge for early redemption of debt decreased $28.8 million primarily due to $29.1 million of premiums paid in 2014 on the early retirement of debt, mostly associated with the settlement of the Senior Unsecured bonds due in October 2016.

DPL – Income Tax Expense
During the year ended December 31, 2016, Income tax expense decreased $298.8 million compared to the prior year primarily due to a pre-tax loss in the current year and the recording of a goodwill impairment in 2015 that did not occur in 2016. This was partially offset by an increase to income tax expense due to non-taxable depreciation of AFUDC equity.

During the year ended December 31, 2015, Income tax expense increased $4.6 million compared to the prior year primarily due to higher pre-tax income (excluding the effect of the 2015 goodwill impairment). This increase was partially offset by an anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return, a deferred tax adjustment related to the expiration of the statute of limitations in 2014 that did not occur in 2015 and an increase in the tax benefits of Internal Revenue Code Section 199 in 2015.

DPL – Discontinued Operations
During the year ended December 31, 2016, Income / (loss) from discontinued operations (net of tax) increased $16.9 million compared to the prior year primarily due to the gain of $49.2 million on the January 1, 2016 sale of DPLER, partially offset by income tax expense of $19.2 million recorded in 2016. Income / (loss) from discontinued operations (net of tax) was $12.4 million for the year ended December 31, 2015, relating to DPLER operations in 2015. See Note 16 – Discontinued Operations in Notes to DPL's Consolidated Financial Statements.


RESULTS OF OPERATIONS BY SEGMENT – DPL Inc.

During the fourth quarter of 2016, DPL's management reassessed our reportable business segments in connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of DP&L’s generation assets to AES Ohio Generation. DPL currently manages the business through two reportable operating segments, the Transmission and Distribution ("T&D") segment and the Generation segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that income / (loss) from continuing operations before income tax best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment
The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 519,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. 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. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.
Generation Segment
The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates peaking generating facilities, and DP&L owns multiple coal-fired and peaking electric generating facilities. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process. Prior to the January 1, 2016 sale of DPLER, DP&L also had full requirements sales to DPLER.

Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s debt and adjustments related to purchase accounting from the Merger. 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. Certain shared and corporate costs are allocated among reporting segments.

Management evaluates segment performance based on income / (loss) from continuing operations before income tax. See Note 14 – Business Segments of Notes to DPL’s Consolidated Financial Statements for additional information regarding DPL’s reportable segments.

The following table presents DPL’s Income / (loss) from continuing operations before income tax by business segment:
  Years ended December 31,
$ in millions 2016 2015 2014
T&D $143.0
 $188.1
 $241.7
Generation (1,353.9) (28.7) (78.0)
Other 417.6
 (390.8) (91.1)
Income / (loss) from continuing operations before income tax $(793.3) $(231.4) $72.6


Statement of Operations Highlights – DPL Inc. – T&D Segment
  Years ended December 31,
$ in millions 2016 2015 2014
Revenues:      
Retail $739.8
 $786.4
 $834.1
Wholesale 16.1
 19.7
 114.2
RTO revenues 45.7
 45.3
 53.6
RTO capacity revenues 6.4
 5.6
 19.9
Total revenues 808.0
 857.0
 1,021.8
       
Cost of revenues:      
       
Net fuel costs 5.3
 (9.0) 21.8
       
Purchased power:      
Purchased power 258.3
 238.1
 283.2
RTO charges 58.6
 60.1
 73.5
RTO capacity charges (0.2) 19.2
 30.3
Net purchased power 316.7
 317.4
 387.0
       
Total cost of revenues 322.0
 308.4
 408.8
       
Gross margins 486.0
 548.6
 613.0
       
Operating expenses:      
Operation and maintenance 179.3
 184.0
 195.7
Depreciation and amortization 71.0
 71.5
 75.5
General taxes 68.0
 70.8
 69.6
Other (0.4) 0.1
 1.0
Total operating expenses 317.9
 326.4
 341.8
       
Operating income 168.1
 222.2
 271.2
       
Other income / (expense), net:      
Investment income 0.4
 0.3
 0.9
Interest expense (24.7) (28.9) (29.8)
Charge for early redemption of debt (0.5) (4.8) —
Other deductions (0.3) (0.7) (0.6)
Total other expense, net (25.1) (34.1) (29.5)
       
Income from continuing operations before income taxes (a) $143.0
 $188.1
 $241.7

(a)For purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. 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.

T&D Segment – Revenues
During the year ended December 31, 2016, the segment’s revenues decreased $49.0 million to $808.0 million from $857.0 million in the same period of the prior year. This decrease was primarily the result of lower average retail rates, partially offset by higher retail volumes, higher wholesale revenues, and higher RTO revenues.
Retail revenues decreased $46.6 million primarily due to an unfavorable $68.7 million retail rate variance, partially offset by a favorable $21.0 million retail volume variance. The unfavorable rate variance was due

to lower average DP&L retail rates, primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, was lower than the non-auction SSO rate. The decrease was also due to the recovery of deferred storm costs in 2015 and the reversion back to ESP 1 rates in September of 2016, partially offset by $20.1 million of revenue associated with energy efficiency programs recorded in 2016. This decrease in rate was partially offset by a volume increase due to warmer summer weather in 2016 as cooling degree days increased by 153 along with increased sales to commercial and industrial customers, partially offset by milder winter weather in the first quarter of 2016 as heating degree days decreased by 129.
Wholesale revenues decreased $3.6 million. These revenues, included in the T&D segment, consist of our 4.9% share of the generation output of OVEC, which is sold into PJM at market prices.
RTO capacity and other revenues increased $1.2 million compared to the prior year.
During the year ended December 31, 2015, the segment’s revenues decreased $164.8 million to $857.0 million from $1,021.8 million in the same period of the prior year. This decrease was primarily the result of lower average retail rates, lower retail volume, lower wholesale revenues, and lower RTO revenues.
Retail revenues decreased $47.7 million primarily due to lower retail prices driven by decreased retail revenue for SSO customers as the competitive auction rate, which represents 60% of DP&L SSO load in 2015 as compared to 10% in 2014, is lower than our non-auction SSO rate, a decrease in the USF program recovery rate in 2015, and higher recovery of transmission costs in the prior year. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015. Sales volume also decreased due to milder winter weather in 2015. The above resulted in an unfavorable $28.7 million retail rate variance and an unfavorable $13.0 million retail volume variance. In addition, there was an unfavorable other miscellaneous variance of $6.0 million.
Wholesale revenues decreased $94.5 million. These revenues, included in the T&D segment, consist of our 4.9% share of the generation output of OVEC, which is sold into PJM at market prices. In addition, for 2014, these revenues include wholesale sales for the Beckjord and East Bend plants, which were either closed or sold in 2014. The decrease in revenue is primarily due to the closing and sale of these plants as well as decreased OVEC revenue.
RTO capacity and other revenues decreased $22.6 million compared to the prior year. This decrease was primarily the result of the closure of Beckjord and the sale of East Bend in 2014, as the revenues associated with these plants were no longer earned in 2015. In addition, this decrease was the result of an $8.3 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.

T&D Segment – Cost of Revenues
During the year ended December 31, 2016, Total cost of revenues increased $13.6 million compared to the prior year. This increase was a result of:
Net fuel costs, which include expense recognition or deferral coinciding with the collection of fuel costs through the regulatory fuel deferral, increased $14.3 million compared to the prior year primarily due to fuel costs deferred in 2015, being collected in 2016.
Net purchased power decreased $0.7 million compared to the prior year. This was driven by the following factors:
◦
Purchased power increased $20.2 million primarily due to an unfavorable price variance driven by prices in the competitive bid process. DP&L T&D now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. The T&D segment purchases power for its SSO load. In 2015, the 40% that was not sourced through the competitive bid process was purchased from the Generation segment at PJM market prices.
◦
RTO capacity and other charges decreased $20.9 million driven by decreased load obligations for retail customers as DP&L's retail load fully transitioned to market and was fully sourced through the competitive bid process in 2016. RTO charges are incurred by DP&L T&D as a member of PJM and primarily include transmission charges within our network which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

During the year ended December 31, 2015, Total cost of revenues decreased $100.4 million compared to the prior year. This decrease was a result of:
Net fuel costs, which include expense recognition or deferral coinciding with the collection of fuel costs through the regulatory fuel deferral and fuel costs associated with plants that were closed or sold in 2014, decreased $30.8 million compared to the prior year primarily due to higher costs in 2014 related to fuel costs from plants that were closed or sold by the end of 2014, partially offset by a higher net deferral of fuel costs in 2015 compared to 2014.
Net purchased power decreased $69.6 million compared to the prior year. This was driven by the following factors:
◦Purchased power decreased $45.1 million primarily due to decreased retail sales and, therefore, decreased SSO load requirements along with decreased average prices. The T&D segment purchases power for its SSO load. In 2015, the 40% that was not sourced through the competitive bid process was purchased from the Generation segment at PJM market prices.
◦
RTO capacity and other charges decreased $24.5 million primarily as a result of the closure of Beckjord and the sale of East Bend in 2014, as the costs associated with these plants were no longer incurred in 2015. In addition, the decrease in these charges was due to decreased load obligations as a result of increased SSO sales being sourced through the competitive auction. RTO charges are incurred by DP&L T&D as a member of PJM and primarily include transmission charges within our network which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.

T&D Segment – Operating Expenses
Operating expenses decreased $8.5 million during the year ended December 31, 2016 and decreased $15.4 million during the year ended December 31, 2015, compared to each prior year. The main drivers of these changes are in the following table:
$ in millions 2016 vs. 2015 2015 vs. 2014
Increase / (decrease) in deferred storm costs as they were recognized in 2015 due to their recovery through customer rates (a)
 $(17.5) $17.5
Increase in alternative energy and energy efficiency programs (a)
 13.2
 4.3
Increase / (decrease) in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
 6.2
 (20.1)
Decrease in expenses due to the reversal of the Economic Development Fund, resulting from the withdrawal of ESP 2 (3.0) —
Increase / (decrease) in General taxes (2.8) 1.2
Decrease in generating facilities operating and maintenance expenses, primarily due the sale of East Bend and closure of Beckjord in 2014 (2.7) (14.6)
Decrease in retirement benefits costs (1.5) (0.9)
Decrease in Depreciation and amortization, primarily due to the sale of East Bend and closure of Beckjord in 2014. (0.5) (4.0)
Other, net 0.1
 1.2
Net change in operating expenses $(8.5) $(15.4)
(a)There is corresponding revenue associated with this program resulting in no impact to Net income.

T&D Segment – Interest Expense
During the year ended December 31, 2016, Interest expense decreased $4.2 million compared to the prior year primarily due to a decrease in carrying costs related to the recovery of deferred storm costs in 2015. In the generation separation order dated September 17, 2014, the PUCO permitted DP&L, upon transfer of the generation assets to AES Ohio Generation, to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. For segment purposes, $750.0 million of debt and the pro rata interest expense associated with that debt has been allocated to the T&D segment. All remaining debt and interest expense has been included in the Generation segment.

During the year ended December 31, 2015, Interest expense did not change materially compared to the prior year.

T&D Segment – Charge for Early Redemption of Debt
During the year ended December 31, 2016, Charge for early redemption of debt decreased $4.3 million primarily due to the 2015 write off of unamortized deferred financing costs associated with refinancing activity.

During the year ended December 31, 2015, Charge for early redemption of debt increased $4.8 million primarily due to the 2015 write off of unamortized deferred financing costs associated with refinancing activity.



Statement of Operations Highlights - DPL Inc. – Generation Segment
  Years ended December 31,
$ in millions 2016 2015 2014
Revenues:      
Retail $0.3
 $0.4
 $0.1
Wholesale 463.6
 786.8
 678.2
RTO revenues 16.7
 24.8
 28.3
RTO capacity revenues 131.0
 144.8
 88.0
Mark-to-market gains / (losses) (0.1) 0.1
 —
Total revenues 611.5
 956.9
 794.6
       
Cost of revenues:      
Cost of fuel:      
Fuel 269.8
 272.1
 307.6
Gains from sale of coal (6.3) (3.0) (1.6)
Mark-to-market losses / (gains) —
 (0.3) 0.4
Net fuel costs 263.5
 268.8
 306.4
       
Purchased power:      
Purchased power 63.7
 303.8
 143.3
RTO charges 19.8
 40.3
 85.6
RTO capacity charges 21.5
 103.3
 77.2
Mark-to-market losses / (gains) (4.4) 6.1
 2.5
Net purchased power 100.6
 453.5
 308.6
       
Total cost of revenues 364.1
 722.3
 615.0
       
Gross margins 247.4
 234.6
 179.6
       
Operating expenses:      
Operation and maintenance 174.7
 171.3
 163.3
Depreciation and amortization 55.4
 72.6
 75.3
General taxes 17.6
 16.0
 18.1
Fixed-asset impairment 1,353.5
 —
 —
Other 0.3
 0.3
 (4.5)
Total operating expenses 1,601.5
 260.2
 252.2
       
Operating loss (1,354.1) (25.6) (72.6)
       
Other income / (expense), net:      
Interest expense (0.4) (2.9) (5.0)
Charge for early redemption of debt —
 (0.2) —
Other deductions 0.6
 —
 (0.4)
Total other expense, net 0.2
 (3.1) (5.4)
       
Loss from continuing operations before income taxes (a) $(1,353.9) $(28.7) $(78.0)

(a)For purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. 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.

Generation Segment - Revenues
During the year ended December 31, 2016, the segment’s revenues decreased $345.4 million to $611.5 million from $956.9 million in the same period of the prior year. This decrease was primarily the result of lower average wholesale

rates, the sale of DPLER in 2016, and lower RTO capacity and other revenues, partially offset by increased wholesale volume.
Wholesale revenues decreased $323.2 million primarily as a result of the 2016 sale of DPLER, which accounted for $304.8 million of wholesale sales in 2015. DP&L had full requirements sales to DPLER in 2015 until the competitive retail business was sold on January 1, 2016. The remaining decrease of $18.4 million was primarily due to lower market prices in 2016, partially offset by a 4.5% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the prior year.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $21.9 million compared to the prior year. RTO transmission and congestion revenue decreased $8.1 million as 2015 congestion revenue charges were higher due to milder winter weather in 2016 than 2015. In addition, revenue realized from the PJM capacity auction decreased $13.8 million in 2016 due to lower capacity cleared and lower price in both the CP and RPM auctions. The capacity price that became effective in June of 2016 was $134/MW-day, compared to $136/MW-day in June 2015.
During the year ended December 31, 2015, the segment’s revenues increased $162.3 million to $956.9 million from $794.6 million in the same period of the prior year. This increase was primarily the result of higher average wholesale prices and higher RTO capacity and other revenues, partially offset by lower wholesale volume.
Wholesale revenues increased $108.6 million. However, the generation segment variance for wholesale revenue for 2015 compared to 2014 should be looked at net of the change in purchased power because it was impracticable to restate the netting for the generation segment in 2014 to be comparable to the netting in 2015. The generation segment had net Wholesale revenues of $483.0 million in 2015, a decrease of $51.9 million from $534.9 million in 2014. This decrease was driven by the segment's decreased full requirements sales to DPLER, as a result of the sale of MC Squared and decreased customers at DPLER in 2015 compared to 2014. In addition, generation was lower in 2015 due to unplanned outages.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, increased $53.3 million compared to the prior year. Revenue realized from the PJM capacity auction increased $56.8 million, as the capacity price that became effective in June 2015 was $136/MW-day compared to $126/MW-day in June 2014. This was partially offset as RTO transmission and congestion revenue decreased $3.5 million due to higher 2014 congestion revenue charges due to extreme weather.
Generation Segment - Cost of Revenues
During the year ended December 31, 2016, Total cost of revenues decreased $358.2 million compared to the prior year. This decrease was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $5.3 million compared to the prior year primarily due to a 7.5% decrease in average fuel cost per MWh and a $3.3 million increase in gains on the sale of coal, partially offset by a 7.2% increase in internal generation.
Net purchased power decreased $352.9 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $240.1 million primarily due to decreased power purchased to source DPLER customers, as DP&L previously had full requirements sales to DPLER in 2015. We purchase power to source retail load in other service territories and to source DPLER customers in 2015. The generation segment also purchases power to meet contracted Wholesale requirements 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.
◦RTO charges decreased $20.5 million primarily as a result of no longer having load obligations on sales to DPLER. RTO charges are incurred as a member of PJM and include costs associated with the segment's load obligations and transmission and congestion losses incurred on the segments wholesale revenues.
◦RTO capacity charges decreased $81.8 million primarily due to the segment no longer providing power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.

◦Mark-to-market gains increased $10.5 million due to less significant decreases in power prices in 2016 causing gains on derivative forward power purchase contracts.
During the year ended December 31, 2015, Total cost of revenues increased $107.3 million compared to the prior year. This increase was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $37.6 million compared to the prior year primarily due to a 5.2% decrease in internal generation as a result of increased outages and a 6.6% decrease in average fuel cost per MWh.
Net purchased power increased $144.9 million compared to the prior year. This increase was driven by the following factors:
◦Purchased power increased $160.5 million. However, the Generation segment variance for Wholesale revenue for 2015 compared to 2014 should be analyzed net of the change in purchased power because the netting for the Generation segment is not comparable to the netting in 2015, as discussed in the Wholesale revenue section above. We purchase power to source retail load in other service territories and to source DPLER customers in 2015 and 2014. The generation segment also purchases power to meet contracted Wholesale requirements 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.
◦RTO charges decreased $45.3 million as a result of higher transmission and congestion charges incurred in 2014 due to severe weather and decreased DPLER load obligations in 2015. RTO charges are incurred as a member of PJM and include costs associated with the segment's load obligations.
◦RTO capacity charges increased $26.1 million driven by a $7.3 million PJM penalty associated with low plant availability in 2015 compared to an approximate $2.4 million penalty recorded in 2014 and higher RTO capacity prices, partially offset by decreased DPLER load obligations in 2015. As noted above, RTO capacity prices are set by an annual auction.
◦Mark-to-market losses decreased $3.6 million.

Generation Segment - Operating Expenses
Operating expenses increased $1,341.3 million during the year ended December 31, 2016 and increased $8.0 million during the year ended December 31, 2015 compared to each prior year. The main drivers of these changes are in the following table:
$ in millions 2016 vs. 2015 2015 vs. 2014
Fixed-asset impairment in 2016 (a)
 $1,353.5
 $—
Decrease in Depreciation and amortization (b)
 (17.2) (2.7)
Increase / (decrease) in generating facilities operating and maintenance expenses (12.0) 13.6
Increase / (decrease) in insurance and claims reserve due to insurance proceeds received from MVIC in 2015 6.5
 (4.2)
Increase / (decrease) in retirement benefits costs 4.3
 (1.8)
Increase in legal and other consulting fees 2.4
 3.0
Increase / (decrease) in General taxes 1.6
 (2.1)
Other, net 2.2
 2.2
Net change in operating expenses $1,341.3
 $8.0

(a)
As the purchase accounting adjustments were not pushed down to DP&L, DPL's Generation segment's fixed-asset impairments, without the effect of the purchase accounting adjustments, were $1,353.5 million during the year ended December 31, 2016. In the second quarter of 2016, DP&L recorded an $857.1 million fixed asset impairment, as DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Killen and certain DP&L peaking generating facilities were not recoverable. In the fourth quarter of 2016, DP&L recorded an additional $496.4 million fixed asset impairment as DP&L performed a long-lived asset impairment analysis for the Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups, as well as the Hutchings gas-fired peaking plant asset group and determined that their carrying amounts were not recoverable. For more information on these impairments, see Note 14 – Fixed-asset Impairment of Notes to DP&L's Consolidated Financial Statements. The difference between the impairment recorded on DPL and the impairment recorded on DP&L represents the difference between the carrying value of the assets prior to the impairments.

(b)During the year ended December 31, 2016, Depreciation and amortization expense decreased $17.2 million compared to the prior year. The decrease was primarily due to the fixed asset impairment in Q2 of 2016, which reduced depreciation expense due to the lower asset values.

Generation Segment - Interest Expense
During the year ended December 31, 2016, Interest expense decreased $2.5 million compared to the prior year due primarily to a reduction of debt at DP&L.

In the generation separation order dated September 17, 2014, the PUCO permitted DP&L, upon transfer of the generation assets to AES Ohio Generation, to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. For segment purposes, $750.0 million of debt and the pro rata interest expense associated with that debt has been allocated to the T&D segment. All remaining debt and interest expense has been included in the Generation segment.

During the year ended December 31, 2015, Interest expense decreased $2.1 million compared to the prior year due primarily to a reduction of debt at DP&L.

Generation Segment – Charge for Early Redemption of Debt
During the years ended December 31, 2016 and December 31, 2015, Charge for early redemption of debt was $0.0 million and $(0.2) million, respectively.


RESULTS OF OPERATIONS – DP&L

Statement of Operations Highlights – DP&L
  Years ended December 31,
$ in millions 2016 2015 2014
Revenues:      
Retail $740.0
 $786.7
 $834.2
Wholesale 453.9
 576.2
 666.0
RTO revenues 58.2
 65.7
 77.6
RTO capacity revenues 113.9
 123.6
 90.5
Mark-to-market gains / (losses) (0.1) 0.1
 —
Total revenues 1,365.9
 1,552.3
 1,668.3
Cost of revenues:      
Cost of fuel:      
Fuel 255.5
 248.0
 315.8
Gains from sale of coal (6.6) (3.1) (1.3)
Mark-to-market losses / (gains) —
 (0.2) 0.4
Net fuel costs 248.9
 244.7
 314.9
Purchased power:      
Purchased power 321.2
 336.5
 322.9
RTO charges 77.2
 94.1
 150.4
RTO capacity charges 20.0
 119.1
 106.7
Mark-to-market losses / (gains) (4.3) 6.0
 2.4
Net purchased power 414.1
 555.7
 582.4
       
Total cost of revenues 663.0
 800.4
 897.3
       
Gross margins 702.9
 751.9
 771.0
       
Operating expenses:      
Operation and maintenance 343.2
 350.5
 355.2
Depreciation and amortization 120.3
 138.2
 144.8
General taxes 83.8
 85.0
 85.7
Gain on termination of contract (27.7) —
 —
Fixed-asset impairment 1,353.5
 —
 —
Other (0.1) 0.4
 (3.5)
Total operating expenses 1,873.0
 574.1
 582.2
       
Operating income / (loss) (1,170.1) 177.8
 188.8
Other income / (expense), net      
Investment income 0.4
 0.3
 0.9
Interest expense (24.5) (30.9) (33.9)
Charge for early redemption of debt (0.5) (5.0) —
Other deductions (0.4) (0.7) (1.1)
Other expense, net (25.0) (36.3) (34.1)
       
Income / (loss) from operations before income tax (a) $(1,195.1) $141.5
 $154.7

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


DP&L – Revenues
The following table provides a summary of changes in DP&L’s Revenues from prior periods:
$ in millions 2016 vs. 2015 2015 vs. 2014
Retail    
Rate $(69.4) $(28.7)
Volume 20.2
 (13.0)
Other 2.5
 (5.8)
Total retail change (46.7) (47.5)
Wholesale    
Rate (111.9) 5.8
Volume (10.4) (95.6)
Total wholesale change (122.3) (89.8)
RTO revenues and RTO capacity revenues    
RTO revenues and RTO capacity revenues (17.2) 21.2
Other    
Unrealized MTM (0.2) 0.1
Total revenues change $(186.4) $(116.0)

During the year ended December 31, 2016, Revenues decreased $186.4 million to $1,365.9 million from $1,552.3 million in the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower wholesale volumes, and lower RTO and RTO capacity revenues, partially offset by higher retail volumes.
Retail revenues decreased $46.7 million primarily due to an unfavorable $69.4 million retail rate variance and a favorable $20.2 million retail volume variance. The unfavorable rate variance was due to lower average DP&L retail rates, primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, was lower than the non-auction SSO rate. The decrease was also due to the recovery of deferred storm costs in 2015 and the reversion back to ESP 1 rates in September of 2016, partially offset by $20.1 million of revenue associated with energy efficiency programs recorded in 2016. This decrease in rate was partially offset by a volume increase due to warmer summer weather in 2016 as cooling degree days increased by 153 along with increased sales to commercial and industrial customers, partially offset by milder winter weather in the first quarter of 2016 as heating degree days decreased by 129. In addition, there was a favorable other miscellaneous variance of $2.5 million.
Wholesale revenues decreased $122.3 million as a result of an unfavorable $111.9 million wholesale rate variance and an unfavorable $10.4 million wholesale volume variance. The price decrease of $111.9 million was primarily due to lower market prices in 2016 and higher average prices on sales to DPLER in 2015. Although DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015, DP&L had a decrease in volume due to the contract termination with DPLER, as DP&L previously had full requirements sales to DPLER in 2015.
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L's transmission assets, regulation services, reactive supply and operating reserves, as well as PJM capacity revenues, decreased $17.2 million. This decrease was the result of a $7.5 million decrease in RTO transmission and congestion revenue, as 2015 congestion revenue charges were higher due to the fact that the winter weather was milder in 2016 than 2015. There was also a $9.7 million decrease in revenue realized from the PJM capacity auction in 2016 due lower capacity cleared and lower prices in both the CP and RPM auctions. The capacity price that became effective in June of 2016 was $134/MW-day, compared to $136/MW-day in June 2015.

During the year ended December 31, 2015, Revenues decreased $116.0 million to $1,552.3 million from $1,668.3 million in the prior year. This decrease was primarily the result lower retail and wholesale volumes and lower average retail rates, partially offset by higher wholesale rates and increased RTO capacity revenues.
Retail revenues decreased $47.5 million primarily due to lower retail prices driven by decreased retail revenue for SSO customers as the competitive auction rate, which represents 60% of DP&L SSO load in 2015 as compared to 10% in 2014, is lower than our non-auction SSO rate, a decrease in the USF program

recovery rate in 2015, and higher recovery of transmission costs in the prior year. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015. Sales volume also decreased due to milder winter weather in 2015. Further, heating degree days decreased by 787, or 13%, while cooling degree days increased by 83, or 8.5%, compared to 2014, which contributed to a volume decrease. The above resulted in an unfavorable $28.7 million retail rate variance and an unfavorable $13.0 million retail volume variance.
Wholesale revenues decreased $89.8 million as a result of an unfavorable $95.6 million wholesale volume variance and a favorable $5.8 million wholesale rate variance. Although DP&L had excess generation available to be sold in the wholesale market in 2015 resulting from 60% of its SSO load being served through the competitive bid process compared to 10% during 2014, there was a 17% decrease in net generation from DP&L's co-owned and operated plants due to the 2014 sale of East Bend, the closing of Beckjord and increased unplanned outages. DP&L also had decreased full requirements sales to DPLER, as a result of the sale of MC Squared and decreased customers at DPLER in 2015 compared to 2014. The average price increase was due to higher prices on sales to DPLER, partially offset by lower market prices.
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, increased $21.2 million. This increase was primarily the result of a $33.1 million increase in revenue realized from the PJM capacity auction. The capacity price that became effective in June 2015 was $136/MW-day compared to $126/MW-day in June 2014. This increase was offset by an $11.9 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.

DP&L – Cost of Revenues
During the year ended December 31, 2016 total cost of revenues decreased $137.4 million compared to the prior year. This decrease was primarily due to:
Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $4.2 million compared to the prior year primarily due to a 4.5% increase in internal generation, partially offset by a 1.4% decrease in average fuel cost per MWh.
Net purchased power decreased $141.6 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $15.3 million primarily due to a $55.7 million volume decrease largely attributable to the fact that DP&L no longer purchases power to source DPLER customers due to the DPLER contract termination associated with the sale of DPLER by DPL on January 1, 2016. The decrease in volume due to the sale of DPLER was partially offset by increased purchases as DP&L now sources 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DP&L purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's. The decrease in volume was also partially offset by an unfavorable price variance of $40.4 million driven by prices in the competitive bid process.
◦
RTO charges decreased $16.9 million primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.
◦
RTO capacity and other costs decreased $99.1 million primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and resulting from the fact that DP&L no longer provides power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.
◦Mark-to-market gains increased $10.3 million due to less significant decreases in power prices in 2016, causing gains on derivative forward power purchase contracts.


During the year ended December 31, 2015 total cost of revenues decreased $96.9 million compared to the prior year. This decrease was primarily due to:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $70.2 million driven by a 17% decrease in internal generation at our plants combined with lower average fuel prices.
Net purchased power decreased $26.7 million compared to the prior year. This increase was driven by the following factors:
◦Purchased power costs increased $13.6 million, primarily due to a $24.3 million price increase, partially offset by a $10.7 million volume decrease. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand. The increase above includes a partial offset resulting from a $10 million regulatory deferral of OVEC costs that are probable for future recovery.
◦
RTO charges decreased $56.3 million as a result of higher transmission and congestion charges incurred in 2014 due to severe weather and decreased load obligations in 2015. RTO charges are incurred as a member of PJM and include costs associated with DP&L’s load obligations for retail customers.
◦RTO capacity and other costs increased $12.4 million driven by a $7.3 million PJM penalty associated with low plant availability in 2015 and higher RTO capacity prices, partially offset by decreased load obligations for retail customers in 2015. As noted above, RTO capacity prices are set by an annual auction.
◦Mark-to-market losses increased $3.6 million.

DP&L – Operation and Maintenance
During the year ended December 31, 2016, Operation and Maintenance expense decreased $7.3 million compared to the prior year. This decrease was a result of:
$ in millions 2016 vs. 2015
Decrease in deferred storm costs as they were all recognized in 2015 due to their recovery through customer rates (a)
 $(17.5)
Decrease in generating facilities operating and maintenance expenses (12.2)
Decrease in expenses due to the reversal of the Economic Development Fund, resulting from the withdrawal of ESP 2 (3.0)
Increase in alternative energy and energy efficiency programs(a)
 13.2
Increase in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
 6.2
Increase in retirement benefits 2.9
Increase in property insurance 1.6
Other, net 1.5
Net change in operation and maintenance expense $(7.3)

(a)There is corresponding revenue associated with this program resulting in no impact to Net income.

During the year ended December 31, 2015, Operation and Maintenance expense decreased $4.7 million compared to the prior year. This decrease was a result of:
$ in millions 2015 vs. 2014
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)

 $(20.1)
Decrease in generating facilities operating and maintenance expenses (5.7)
Increase in deferred storm costs as they were recognized in 2015 due to their recovery through customer rates (a)

 17.5
Increase in alternative energy and energy efficiency programs (a)
 3.9
Other, net (0.3)
Net change in operation and maintenance expense $(4.7)

(a)There is corresponding revenue associated with this program resulting in no impact to Net income.

DP&L – Depreciation and Amortization
During the year ended December 31, 2016, Depreciation and amortization expense decreased $17.9 million compared to the prior year. The decrease was primarily due to the fixed asset impairment in Q2 of 2016, which reduced depreciation expense due to the lower asset values. This was partially offset by an increase in the ARO for asbestos removal and remediation at the closed Beckjord plant. As this plant is no longer in operation, the entire impact of this adjustment was recorded as depreciation expense.

During the year ended December 31, 2015, Depreciation and amortization expense decreased $6.6 million compared to the prior year. The decrease is primarily due to the sale of the East Bend Plant and the retirement of the Beckjord Plant, partially offset by increased depreciation associated with increased ARO assets and net plant additions.

DP&L – Fixed-asset Impairment and Gain on Asset Sale
During the year ended December 31, 2016, DP&L recorded an impairment of fixed assets of $1,353.5 million. In the second quarter of 2016, DP&L recorded an $857.1 million fixed-asset impairment, as DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Stuart, Killen and Zimmer were not recoverable. In the fourth quarter of 2016, DP&L recorded an additional $496.4 million fixed-asset impairment as DP&L performed a long-lived asset impairment analysis for the Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups, as well as the Hutchings gas-fired peaking plant asset group and determined that their carrying amounts were not recoverable.

During the year ended December 31, 2014, DP&L recorded a gain of $4.5 million on the sale of its interest in the East Bend generating station.

See Note 14 – Fixed-asset Impairment of the Notes to DP&L’s Financial Statements for more information on the impairments.

DP&L – Gain on termination of contract
During the year ended December 31, 2016, DP&L recorded $27.7 million related to the termination of a contract DP&L had with DPLER for the supply of electricity.

DP&L – Interest Expense
During the year ended December 31, 2016, interest expense decreased $6.4 million compared to the prior year primarily due to lower average debt balances at DP&L during 2016, as well as a decrease in carrying costs primarily related to the recovery of deferred storm costs in 2015.

During the year ended December 31, 2015, interest expense decreased $3.0 million compared to the prior year due to a reduction in outstanding debt and lower interest rates on DP&L’s senior secured tax-exempt First Mortgage Bonds.

DP&L – Charge for Early Redemption of Debt
During the year ended December 31, 2016, Charge for early redemption of debt decreased $4.5 million primarily due to the 2015 write off of unamortized deferred financing costs associated with refinancing activity.

During the year ended December 31, 2015, Charge for early redemption of debt increased $5.0 million primarily due to the 2015 write off of unamortized deferred financing costs associated with refinancing activity.

DP&L – Income Tax Expense
During the year ended December 31, 2016, Income tax expense decreased $457.5 million compared to the prior year primarily due to a pre-tax loss in the current year, driven by the fixed asset impairments.

During the year ended December 31, 2015, Income tax expense decreased $4.6 million compared to the prior year primarily due to decreases in pre-tax income, an anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return and an increase in the tax benefits of Internal Revenue Code Section 199 in 2015. Partially offsetting the decrease is a deferred tax adjustment related to the prior year expiration of the statute of limitations that did not occur in 2015.

RESULTS OF OPERATIONS BY SEGMENT – DP&L

During the fourth quarter of 2016, DP&L’s management reassessed our separate reportable business segments in connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of DP&L’s generation assets to AES Ohio Generation. DP&L currently manages the business through two reportable operating segments, the Transmission and Distribution ("T&D") segment and the Generation segment. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that income / (loss) from operations before income tax best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment
The segment description and the results of operations of the T&D segment for DP&L are identical in all material respects and for all periods presented to those of the T&D segment for DPL,which are included above in this Form 10-K. We do not believe that additional discussions of the results of operations of DP&L’s T&D segment would enhance an understanding of this business since these discussions are already included under the DPL discussions above.
Generation Segment
The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's generation segmentowns multiple coal-fired and peaking electric generating facilities. DP&L's generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process. Prior to the January 1, 2016 DPL sale of DPLER, DP&L also had full requirements sales to DPLER.

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. Certain shared and corporate costs are allocated among reporting segments.

Management evaluates segment performance based on income / (loss) from operations before income tax. See Note 13 – Business Segments of Notes to DP&L’s Consolidated Financial Statements for additional information regarding DP&L’s reportable segments.

The following table presents DP&L’s Income / (loss) from operations before income tax by business segment:
  Years ended December 31,
$ in millions 2016 2015 2014
T&D $143.6
 $189.0
 $242.6
Generation (1,338.7) (47.5) (87.9)
Income / (loss) from operations before income tax $(1,195.1) $141.5
 $154.7


Statement of Operations Highlights – DP&L – Generation Segment
  Years ended December 31,
$ in millions 2016 2015 2014
Revenues:      
Retail $0.2
 $0.3
 $0.1
Wholesale 437.8
 762.8
 657.1
RTO revenues 12.5
 20.4
 24.0
RTO capacity revenues 107.5
 118.0
 70.6
Mark-to-market gains / (losses) (0.1) 0.1
 —
Total revenues 557.9
 901.6
 751.8
       
Cost of revenues:      
Cost of fuel:      
Fuel 249.9
 257.0
 294.3
Gains from sale of coal (6.3) (3.1) (1.6)
Mark-to-market losses / (gains) —
 (0.2) 0.4
Net fuel costs 243.6
 253.7
 293.1
       
Purchased power:      
Purchased power 62.9
 302.2
 140.1
RTO charges 18.6
 36.5
 81.8
RTO capacity charges 20.2
 99.9
 76.4
Mark-to-market losses / (gains) (4.3) 6.0
 2.4
Net purchased power 97.4
 444.6
 300.7
       
Total cost of revenues 341.0
 698.3
 593.8
       
Gross margins 216.9
 203.3
 158.0
       
Operating expenses:      
Operation and maintenance 163.9
 166.5
 159.5
Depreciation and amortization 49.3
 66.7
 69.3
General taxes 15.8
 14.2
 16.1
Gain on termination of contract (27.7) —
 —
Fixed-asset impairment 1,353.5
 —
 —
Other 0.3
 0.3
 (4.5)
Total operating expenses 1,555.1
 247.7
 240.4
       
Operating income (1,338.2) (44.4) (82.4)
       
Other income / (expense), net:      
Interest expense (0.5) (2.9) (5.0)
Other deductions —
 (0.2) (0.5)
Total other expense, net (0.5) (3.1) (5.5)
       
Income / (loss) from operations before income tax (a)
 $(1,338.7) $(47.5) $(87.9)

(a)For purposes of discussing operating results, we present and discuss Income / (loss) operations before income tax. 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.

Generation Segment – Revenues
During the year ended December 31, 2016, the segment’s revenues decreased $343.7 million to $557.9 million from $901.6 million in the same period of the prior year. This decrease was primarily the result of lower average wholesale

rates, the sale of DPLER in 2016, and lower RTO capacity and other revenues, partially offset by increased wholesale volume.
Wholesale revenues decreased $325.0 million primarily as a result of the 2016 sale of DPLER, which accounted for $304.8 million of wholesale sales in 2015. DP&L had full requirements sales to DPLER in 2015 until the competitive retail business was sold on January 1, 2016. The remaining decrease of $20.2 million was primarily due to lower market prices in 2016, partially offset by a 4.5% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the prior year.
RTO capacity and other revenues decreased $18.4 million compared to the prior year. RTO transmission and congestion revenue decreased $7.9 million as 2015 congestion revenue charges were higher due to milder winter weather in 2016 than 2015. In addition, revenue realized from the PJM capacity auction decreased $10.5 million in 2016 due to lower capacity cleared and lower price in both the CP and RPM auctions. The capacity price that became effective in June of 2016 was $134/MW-day, compared to $136/MW-day in June 2015.
During the year ended December 31, 2015, the segment’s revenues increased $149.8 million to $901.6 million from $751.8 million in the same period of the prior year. This increase was primarily the result of higher average wholesale prices and higher RTO capacity and other revenues, partially offset by lower wholesale volume.
Wholesale revenues increased $105.7 million. However, the generation segment variance for wholesale revenue for 2015 compared to 2014 should be looked at net of the change in purchased power because it was impracticable to restate the netting for the generation segment in 2014 to be comparable to the netting in 2015. The generation segment had net Wholesale revenues of $460.6 million in 2015, a decrease of $56.4 million from $517.0 million in 2014. This decrease was driven by the segment's decreased full requirements sales to DPLER, as a result of the sale of MC Squared and decreased customers at DPLER in 2015 compared to 2014. In addition, generation was lower in 2015 due to unplanned outages.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, increased $43.8 million compared to the prior year. Revenue realized from the PJM capacity auction increased $47.4 million, as the capacity price that became effective in June 2015 was $136/MW-day compared to $126/MW-day in June 2014. This was partially offset as RTO transmission and congestion revenue decreased $3.6 million due to higher 2014 congestion revenue charges due to extreme weather.
Generation Segment – Cost of Revenues
During the year ended December 31, 2016, Total cost of revenues decreased $357.3 million compared to the prior year. This decrease was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $10.1 million compared to the prior year primarily due to a 7.0% decrease in average fuel cost per MWh and a $3.2 million increase in gains on the sale of coal, partially offset by a 4.5% increase in internal generation.
Net purchased power decreased $347.2 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $239.3 million primarily due to decreased power purchased to source DPLER customers, as DP&L previously had full requirements sales to DPLER in 2015. We purchase power to source retail load in other service territories and to source DPLER customers in 2015. The generation segment also purchases power to meet contracted Wholesale requirements 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.
◦RTO charges decreased $17.9 million primarily as a result of no longer having load obligations on sales to DPLER. RTO charges are incurred as a member of PJM and include costs associated with the segment's load obligations and transmission and congestion losses incurred on the segments wholesale revenues.
◦RTO capacity charges decreased $79.7 million primarily due to the segment no longer providing power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.

◦Mark-to-market losses (gains) increased $10.3 million due to less significant decreases in power prices in 2016 causing gains on derivative forward power purchase contracts.
During the year ended December 31, 2015, Total cost of revenues increased $104.5 million compared to the prior year. This increase was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $39.4 million compared to the prior year primarily due to a 6.6% decrease in internal generation as a result of increased outages and a 6.5% decrease in average fuel cost per MWh.
Net purchased power increased $143.9 million compared to the prior year. This increase was driven by the following factors:
◦Purchased power increased $162.1 million. However, the Generation segment variance for Wholesale revenue for 2015 compared to 2014 should analyzed net of the change in purchased power because the netting for the Generation segment is not comparable to the netting in 2015, as discussed in the Wholesale revenue section above. We purchase power to source retail load in other service territories and to source DPLER customers in 2015 and 2014. The generation segment also purchases power to meet contracted Wholesale requirements 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.
◦RTO charges decreased $45.3 million as a result of higher transmission and congestion charges incurred in 2014 due to severe weather and decreased DPLER load obligations in 2015. RTO charges are incurred as a member of PJM and include costs associated with the segment's load obligations.
◦RTO capacity charges increased $23.5 million driven by a $7.3 million PJM penalty associated with low plant availability in 2015 compared to an approximate $2.4 million penalty recorded in 2014 and higher RTO capacity prices, partially offset by decreased DPLER load obligations in 2015. As noted above, RTO capacity prices are set by an annual auction.
◦Mark-to-market losses increased $3.6 million.

Generation Segment - Operating Expenses
Operating expenses increased $1,307.4 million during the year ended December 31, 2016 and increased $7.3 million during the year ended December 31, 2015, compared to each prior year. The main drivers of these changes are in the following table:
$ in millions 2016 vs. 2015 2015 vs. 2014
Fixed-asset impairment in 2016 (a)
 $1,353.5
 $—
Gain on termination of contract (27.7) —
Decrease in Depreciation and amortization (b)
 (17.4) (2.6)
Increase / (decrease) in generating facilities operating and maintenance expenses (11.2) 7.6
Increase / (decrease) in retirement benefits costs 4.3
 (1.8)
Increase in legal and other consulting fees 2.4
 2.9
Increase / (decrease) in General taxes 1.6
 (1.9)
Other, net 1.9
 3.1
Net change in operating expenses $1,307.4
 $7.3

(a)
During the year ended December 31, 2016, DP&L recorded an impairment of fixed-assets of $1,353.5 million. In the second quarter of 2016, DP&L recorded an $857.1 million fixed asset impairment, as DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Stuart, Killen and Zimmer were not recoverable. In the fourth quarter of 2016, DP&L recorded an additional $496.4 million fixed asset impairment as DP&L performed a long-lived asset impairment analysis for the Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups, as well as the Hutchings gas-fired peaking plant asset group and determined that their carrying amounts were not recoverable. For more information on these impairments, see Note 14 – Fixed-asset Impairment of Notes to DP&L's Consolidated Financial Statements.
(b)During the year ended December 31, 2016, Depreciation and amortization expense decreased $17.4 million compared to the prior year. The decrease was primarily due to the fixed asset impairment in Q2 of 2016, which reduced depreciation expense due to the lower asset values.


Generation Segment – Interest Expense
During the year ended December 31, 2016, Interest expense decreased $2.4 million compared to the prior year due primarily to a reduction of debt at DP&L attributable to the Generation segment. In the generation separation order dated September 17, 2014, the PUCO permitted DP&L to temporarily maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018. For segment purposes, $750.0 million of debt has been allocated to the T&D segment and all remaining debt is included in the Generation segment.

During the year ended December 31, 2015, Interest expense decreased $2.1 million compared to the prior year due primarily to a reduction of debt at DP&L.

KEY TRENDS AND UNCERTAINTIES

During 2017 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, energy efficiency and wholesale prices on financial results. In addition, DPL financial results are likely to be driven by many factors including, but not limited to:
PJM capacity prices,
Outcome of DP&L's pending ESP 3 case, including the amount of non-bypassable revenue;
Outcome of DP&L's pending distribution rate case;
Operational performance of generation facilities;
Recovery in the power market, particularly as it relates to an expansion in dark spreads;
Sale or transfer of DP&L generation assets; and
DPL's ability to reduce its cost structure.

Operational

On January 10, 2017, a high pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As the damage assessment process is currently ongoing, we cannot determine the impact to operations or capacity at this time.

Macroeconomic and Political
The outcome of the 2016 U.S. elections could result in significant changes to U.S. tax laws, environmental policies, and energy policies, the impact of which is uncertain.

Regulatory Environment
For a comprehensive discussion of the market structure and regulation of DPL and DP&L, see Part I, Item 1 - Business – Competition and Regulation.

Ohio law requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. The terms and conditions of DP&L’s current SSO are provided under the most-recently approved ESP. Although it had been in effect since January 2014, on June 20, 2016, the Ohio Supreme Court (Court) issued an opinion in the appeal of DP&L’s ESP that had been approved by the PUCO for the years 2014 - 2016 and which, among other matters, permitted DP&L to collect a non-bypassable SSR equal to $110 million per year from 2014 - 2016 and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. DP&L’s own generation was phased-out of supplying SSO service over the three-year period. Beginning January 1, 2016, DP&L's SSO was 100% sourced through the competitive bid. In the opinion, the Court stated that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP and implement rates consistent with those in effect prior to 2014. Those rates will be in effect until rates consistent with DP&L’s pending ESP 3 filing are approved and effective.

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years supporting the alternative described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to

allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities DP&L may incur.
On January 30, 2017, DP&L, in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:
The establishment of a five-year Distribution Modernization Rider designed to collect $90.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure;
The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35.0 million in revenue per year to enable the implementation of smart grid and advanced metering ending after the fifth year of the term of the ESP;
A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC);
A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants;
A commitment to develop or procure wind and/or solar energy projects in Ohio; and
Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing on the stipulation has been scheduled for March 8, 2017. A final decision by the PUCO is expected at the end of the second quarter or early in the third quarter of 2017. If the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh on DP&L's SSO, can expect a monthly bill increase of $2.39. There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.
In connection with any sale or exiting of our generation plants as contemplated by the ESP settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

CAPITAL RESOURCES AND LIQUIDITY

Cash and cash equivalents for DPL and DP&L was $54.6 million and $1.6 million, respectively, at December 31, 2016. At that date, neither DPL nor DP&L had short-term investments. DPL and DP&L had aggregate principal amounts of debt outstanding of $1,883.6 million and $763.0 million, respectively.

Approximately $29.7 million of DPL's debt and $4.7 million of DP&L's debt matures within the next twelve months, which we expect to repay using a combination of cash on hand, net cash provided by operating activities and/or net proceeds from the issuance of new debt.

We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on our financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in the regulatory determinations could affect the cash flows and results of operations of our business.


CASH FLOWS
DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. The following table summarizes the cash flows of DPL:
DPL Years ended December 31,
$ in millions 2016 2015 2014
Net cash provided by operating activities $267.1
 $308.5
 $244.1
Net cash used in investing activities (77.8) (136.7) (112.6)
Net cash used in financing activities (167.1) (156.4) (167.7)
       
Net increase / (decrease) in cash 22.2
 15.4
 (36.2)
Balance at beginning of period 32.4
 17.0
 53.2
Cash and cash equivalents at end of period $54.6
 $32.4
 $17.0

DPL – Net cash from operating activities
  For the years ended December 31, $ change
$ in millions 2016 2015 2014 2016 vs. 2015 2015 vs. 2014
Net loss $(485.2) $(239.0) $(74.6) $(246.2) $(164.4)
Depreciation and amortization 138.0
 143.6
 147.6
 (5.6) (4.0)
Impairment expenses 859.0
 317.0
 147.3
 542.0
 169.7
Charge for early redemption of debt 3.1
 2.1
 30.9
 1.0
 (28.8)
Other adjustments to Net loss (359.7) (10.9) 16.8
 (348.8) (27.7)
Net loss, adjusted for non-cash items 155.2
 212.8
 268.0
 (57.6) (55.2)
Net change in operating assets and liabilities 111.9
 95.7
 (23.9) 16.2
 119.6
Net cash provided by operating activities $267.1
 $308.5
 $244.1
 $(41.4) $64.4

Fiscal year 2016 versus 2015:
The net change in operating assets and liabilities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was driven by the following:
$ in millions$ Change
Increase from inventory primarily due to lower coal purchases in 2016$41.0
Decrease from accounts receivable primarily due to timing of collections(19.2)
Other(5.6)
Total increase in cash from changes in operating assets and liabilities$16.2

Fiscal year 2015 versus 2014:
The net change in operating assets and liabilities for the year ended December 31, 2015 compared to the year ended December 31, 2014 was driven by the following:
$ in millions$ Change
Increase from Accounts receivable primarily due to the settlement of a receivable balance related to the sale of MC Squared in 2015 and timing of collections.$42.9
Increase from Other current and deferred liabilities primarily related to a one-time payment in 2014 to terminate an unfavorable coal contract30.2
Increase from Accrued taxes payable is primarily due to an increase in accrued federal income tax expense year over year.23.1
Increase from Deferred regulatory costs, net is primarily due to collection of deferred storm costs in 2015.16.4
Other7.0
Total increase in cash from changes in operating assets and liabilities$119.6


DPL – Net cash from investing activities
During the year ended December 31, 2016, net cash used for investing activities was primarily related to capital expenditures, and an increase in restricted cash due to collateral requirements, partially offset by proceeds from the sale of property.

During the year ended December 31, 2015, net cash used for investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.

During the year ended December 31, 2014, net cash used for investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.

DPL – Net cash from financing activities
During the year ended December 31, 2016, net cash used for financing activities primarily relates to the retirement of $577.8 million of debt, and redemption of $23.5 million of preferred stock, partially offset by a $442.8 million issuance of new debt.

During the year ended December 31, 2015, net cash used for financing activities primarily relates to the retirement of $474.5 million of debt, partially offset by a $325.0 million issuance of new debt.

During the year ended December 31, 2014, net cash used for financing activities primarily relates to the redemption of $335.0 million of debt and associated redemption premiums, partially offset by a $200.0 million issuance of new debt.

The following table summarizes the cash flows of DP&L:

DP&L Years ended December 31,
$ in millions 2016 2015 2014
Net cash provided by operating activities $264.8
 $256.7
 $251.7
Net cash used in investing activities (133.4) (122.5) (108.5)
Net cash used in financing activities (135.2) (134.2) (160.7)
       
Net increase / (decrease) in cash (3.8) —
 (17.5)
Balance at beginning of period 5.4
 5.4
 22.9
Cash and cash equivalents at end of period $1.6
 $5.4
 $5.4

DP&L – Net cash from operating activities
  For the years ended December 31, $ change
$ in millions 2016 2015 2014 2016 vs. 2015 2015 vs. 2014
Net income / (loss) $(772.7) $106.4
 $115.0
 $(879.1) $(8.6)
Depreciation and amortization 123.2
 141.1
 147.9
 (17.9) (6.8)
Impairment expenses 1,353.5
 —
 —
 1,353.5
 —
Other adjustments to Net income / (loss) (481.7) (13.1) 6.1
 (468.6) (19.2)
Net income / (loss), adjusted for non-cash items 222.3
 234.4
 269.0
 (12.1) (34.6)
Net change in operating assets and liabilities 42.5
 22.3
 (17.3) 20.2
 39.6
Net cash provided by operating activities $264.8
 $256.7
 $251.7
 $8.1
 $5.0


Fiscal year 2016 versus 2015:
The net change in operating assets and liabilities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was driven by the following:
$ in millions$ Change
Increase from inventory primarily due to lower coal purchases compared to prior year$41.3
Decrease from accounts receivable primarily due to timing of collections(38.4)
Increase from accounts payable due to timing of payments21.8
Other(4.5)
Total increase in cash from changes in operating assets and liabilities$20.2

Fiscal year 2015 versus 2014:
The net change in operating assets and liabilities for the year ended December 31, 2015 compared to the year ended December 31, 2014 was driven by the following:
$ in millions$ Change
Increase from accounts receivable due to timing of collections$35.8
Increase from Deferred regulatory costs, net is primarily due to collection of deferred storm costs in 2015.16.4
Increase from inventory primarily due to lower coal purchases compared to prior year15.5
Decrease from accounts payable due to timing of payments(38.2)
Other10.1
Total increase in cash from changes in operating assets and liabilities$39.6

DP&L – Net cash from investing activities
During the year ended December 31, 2016, net cash used for investing activities was primarily related to capital expenditures, and an increase in restricted cash due to collateral requirements, partially offset by insurance proceeds.

During the year ended December 31, 2015, net cash used for investing activities was primarily related to capital expenditures, partially offset by insurance proceeds.

During the year ended December 31, 2014, net cash used for investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.

DP&L – Net cash from financing activities
During the year ended December 31, 2016, net cash used for financing activities primarily relates to the retirement of $445.3 million of long-term debt, $70.0 million in dividends paid on common stock to parent, related party repayments, net of related party borrowings of $30.0 million, and redemption of $23.5 million of preferred stock, partially offset by the issuance of $442.8 million of new debt.

During the year ended December 31, 2015, net cash used for financing activities primarily relates to the retirement of $314.4 million of long-term debt, $50.0 million in dividends paid on common stock to parent, partially offset by the issuance of $200.0 million of new debt, and $35.0 million of related party borrowings.

During the year ended December 31, 2014, net cash used for financing activities primarily relates to $159.0 million in dividends paid on common stock to DPL.

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, taxes and dividend payments. For 2017 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as our internal liquidity needs and market conditions warrant.

We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods.

At December 31, 2016, DPL and DP&L have access to the following revolving credit facilities:
$ in millions Type Maturity Commitment Amounts available as of December 31, 2016
DPL Revolving July 2020 $205.0
 $203.3
         
DP&L Revolving July 2020 175.0
 173.6
         
      $380.0
 $376.9

DP&L has an unsecured revolving credit agreement with a syndicated bank group. Prior to refinancing the facility on July 31, 2015, as discussed below, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.

On July 31, 2015, DP&L refinanced its revolving credit facility, reducing the total size from $300.0 million to $175.0 million, with a $50.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million, and extending the term of the facility from May 2018 to July 2020. At December 31, 2016, DP&L had no draws under this facility and had two letters of credit in the aggregate amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L.

DPL has a revolving credit facility. This facility has a letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility. Prior to refinancing the facility on July 31, 2015, as discussed below, this facility was unsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million, and had a five year term expiring on May 10, 2018; with a springing maturity, meaning that if DPL had not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility would have been July 15, 2016.

On July 31, 2015, DPL refinanced its revolving credit facility, increasing the total size from $100.0 million to $205.0 million, with a $200.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $95.0 million This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by AES Ohio Generation secured by mortgages on assets of AES Ohio Generation. The refinancing extended the life of the facility from May 2018 to July 2020. DPL's new credit facility has a springing maturity feature, replacing the previous springing maturity feature, providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019.

Capital Requirements

Construction Additions
  Actual Projected
$ in millions 2014 2015 2016 2017 2018 2019
DPL $116
 $132
 $140
 $172
 $174
 $139
             
DP&L $112
 $124
 $119
 $125
 $91
 $90

Planned construction additions for 2017 relate primarily to new investments in and upgrades to DP&L’s electric generating station 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. As discussed previously, DP&L anticipates separating its generation assets during 2017. Accordingly, a portion of the estimated capital

expenditures related to the generation assets of $23.0 million are not included in DP&L’s estimated spending for 2017 in the table above. Those estimated costs are included in the DPL amounts.

DPL is projecting to spend an estimated $485.0 million in capital projects for the period 2017 through 2019. DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions, of which DP&L is a member. NERC has recently changed the definition of the Bulk Electric System 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 $11.3 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
The DPL revolving credit facility and term loan agreement have a Total Debt to EBITDA ratio that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down to not exceed 6.25 to 1.00 for any fiscal quarter ending March 31, 2019 through December 31, 2019; and it then steps down not to exceed 5.75 to 1.00 for any fiscal quarter ending March 31, 2020 through July 31, 2020. As of December 31, 2016, this financial covenant was met with a ratio of 5.27 to 1.00.

The DPL revolving credit facility and term loan agreement also have an EBITDA to Interest Expense ratio that is calculated at the end of each fiscal quarter by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreements, is to be not less than 2.10 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps up to be not less than 2.25 to 1.00 for any fiscal quarter ending March 31, 2019 through July 31, 2020. As of December 31, 2016, this financial covenant was met with a ratio of 3.30 to 1.00.

DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the new $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that after separation required compliance with this financial covenant shall be suspended (a) any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility or (b) for the time period January 1, 2017 to December 31, 2017 (as modified by the amendment described below) if during such time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment DP&L’s Total Debt to Total Capitalization ratio for the period ending December 31, 2016 is 0.53 to 1.00, compared to 0.68 to 1.00 before the amendment. The amendment also changed, for each amendment, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.


The second financial covenant measures DP&L’s EBITDA to Interest Expense ratio. Both prior to and after completion of the separation of DP&L's generation assets from its transmission and distribution assets, DP&L's EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. The ratio is calculated at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. As of December 31, 2016, DP&L met this financial covenant with an EBITDA to Interest Expense ratio of 12.08 to 1.00.

Debt Ratings
During 2015, Fitch downgraded DPL's senior unsecured debt rating. Standard & Poor’s and Moody’s ratings did not change. During 2016, Fitch, Moody's and Standard & Poor's moved their outlook on both DPL and DP&L from stable to negative.

The following table outlines the debt ratings and outlook for DPL and DP&L, along with the effective or affirmed date of each rating.
DPLDP&LOutlookEffective or Affirmed
Fitch Ratings
BB(a) / BB-(b)
BBB (c)
NegativeJuly 2016
Moody's Investors Service, Inc.
Ba3 (b)
Baa2 (c)
NegativeAugust 2016
Standard & Poor's Financial Services LLC
BB (b)
BBB- (c)
NegativeNovember 2016

Credit Ratings
The following table outlines the credit ratings (issuer/corporate rating) and outlook for each company, along with the effective or affirmed dates of each rating and outlook for DPL and DP&L.
DPLDP&LOutlookEffective or Affirmed
Fitch RatingsB+BB+NegativeJuly 2016
Moody's Investors Service, Inc.Ba3Baa3NegativeAugust 2016
Standard & Poor's Financial Services LLCBBBBNegativeNovember 2016

(a)
Rating relates to DPL’s Senior secured debt.
(b)
Rating relates to DPL's Senior unsecured debt.
(c)
Rating relates to DP&L’s Senior secured debt.

If the rating agencies were to reduce our debt or credit ratings further, 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 certain contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities. Non-investment grade companies, such as DPL, may experience higher costs to issue new securities. DP&L is still considered investment grade by one of the three rating agencies above.

Off-Balance Sheet Arrangements

DPL – Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiary, AES Ohio Generation, 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 this subsidiary's intended commercial purposes. During the year ended December 31, 2016, 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 December 31, 2016, DPL had $16.6 million of guarantees to third parties for future financial or performance assurance under such agreements on behalf of AES Ohio Generation. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of AES Ohio Generation 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 Consolidated Balance Sheets was $2.3 million at December 31, 2016 and $0.5 million at December 31, 2015.


DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2016, DP&L could be responsible for the repayment of 4.9%, or $74.2 million, of a $1,514.3 million debt obligation comprised of both fixed and variable rate securities with maturities between 2017 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2016, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2016, these include:
  Payments due in:
$ in millions Total 
Less than
1 year
 
2 - 3
years
 
4 - 5
years
 
More than
5 years
DPL:          
Long-term debt $1,883.6
 $29.7
 $259.2
 $1,039.2
 $555.5
Interest payments 575.8
 102.5
 198.8
 152.6
 121.9
Pension and postretirement payments 285.2
 27.0
 55.2
 56.4
 146.6
Coal and limestone contracts (a)
 284.3
 230.3
 54.0
 —
 —
Purchase orders and other contractual obligations 109.8
 43.1
 33.6
 33.1
 —
Total contractual obligations $3,138.7
 $432.6
 $600.8
 $1,281.3
 $824.0

  Payments due in:
$ in millions Total 
Less than
1 year
 
2 - 3
years
 
4 - 5
years
 
More than
5 years
DP&L:          
Long-term debt $763.0
 $4.7
 $9.2
 $209.1
 $540.0
Interest payments 239.1
 27.4
 54.2
 47.8
 109.7
Pension and postretirement payments 285.2
 27.0
 55.2
 56.4
 146.6
Coal and limestone contracts (a)
 284.3
 230.3
 54.0
 —
 —
Purchase orders and other contractual obligations 109.8
 43.1
 33.6
 33.1
 —
Total contractual obligations $1,681.4
 $332.5
 $206.2
 $346.4
 $796.3

(a)
Total at DP&L operated units.

Long-term debt:
DPL’s Long-term debt at December 31, 2016 consists of DPL’s unsecured notes, secured term loan and Capital Trust II securities, along with DP&L’s First Mortgage Bonds, tax-exempt First Mortgage Bonds and the Wright-Patterson Air Force Base (WPAFB) note. These long-term debt amounts include current maturities but exclude unamortized debt discounts, premiums and fair value adjustments.

DP&L’s Long-term debt at December 31, 2016 consists of its First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

See Note 8 – Debt of the Notes to DPL’s Consolidated Financial Statements and Note 7 – Debt of the Notes to DP&L’s Financial Statements.

Interest payments:
Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2016.

Pension and postretirement payments:
At December 31, 2016, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 10 – Benefit Plans of Notes to DPL’s Consolidated Financial Statements and Note 9 – Benefit Plans of Notes to DP&L’s Financial Statements. These estimated future benefit payments are projected through 2026. This amount also includes postretirement benefit costs.


Coal contracts:
DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

Purchase orders and other contractual obligations:
At December 31, 2016, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

Reserve for uncertain tax positions:
Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $3.7 million at December 31, 2016, we are unable to make a reliable estimate of the periods of cash settlement with the respective tax authorities and have not included such amounts in the contractual obligations table above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

DPL’s Consolidated Financial Statements and DP&L’s 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. Our significant accounting policies are described in Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DPL's Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L's Financial Statements.

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 allowances for deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.

Revenue Recognition (including Unbilled Revenue)
We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. The determination of energy sales to customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. We recognize revenues using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, projected line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Given our estimation method and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.

Income Taxes
We are subject to federal and state income taxes. Our income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the U.S. Internal Revenue Service and other tax authorities. We regularly assess the potential outcome of tax examinations when determining the adequacy of our income tax provisions by considering the technical merits of the filing position, case law, and results of previous tax examinations. Accounting guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold and measurement requirements for financial statement reporting of our income tax positions. Tax reserves have been established which we believe to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While we believe that the amount of the tax reserves is reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

Regulatory Assets and Liabilities
Application of the provisions of GAAP relating to regulatory accounting requires us to reflect the effect of rate regulation in DPL’s Consolidated Financial Statements and DP&L’s Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by non-regulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as Regulatory assets that otherwise would be expensed by non-regulated companies. Likewise, we recognize Regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenses that are not yet incurred. Regulatory assets are amortized into expense and Regulatory liabilities are amortized into income over the recovery period authorized by the regulator.

We evaluate our Regulatory assets to determine whether or not they are probable of recovery through future rates and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period the assessment is made. We currently believe the recovery of our Regulatory assets is probable. See Note 3 – Regulatory Matters of Notes to DPL’s Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s Financial Statements.

AROs
In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time. See Note 4 – Property, Plant and Equipment of Notes to DPL's Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L’s Financial Statements for more information.

Impairments
In accordance with the provisions of GAAP relating to the accounting for goodwill, goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; 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. See Note 7 – Goodwill of Notes to DPL’s Consolidated Financial Statements discussing the impairment of goodwill at DPL in 2015 and 2014.

In accordance with the provisions of GAAP relating to the accounting for impairments, long-lived assets to be held and used are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used are recognized based on the fair

value of the asset. We determine the fair value of these assets based upon estimates of future cash flows, market value of similar assets, if available, or independent appraisals, if required. In analyzing the fair value and recoverability using future cash flows, we make projections based on a number of assumptions and estimates of growth rates, future economic conditions, assignment of discount rates and estimates of terminal values. An impairment loss is recognized if the carrying amount of the long-lived asset is not recoverable from its undiscounted cash flows. The measurement of impairment loss is the difference between the carrying amount and fair value of the asset. See Note 15 – Fixed-asset Impairment of Notes to DPL’s Consolidated Financial Statements and Note 14 – Fixed-asset Impairment of Notes to DP&L’s Financial Statements discussing the impairment of long-lived assets in 2016 and 2014.

Pension and Postretirement Benefits
We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and post-retirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DPL's Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L's Financial Statements. Also see Note 10 – Benefit Plans of Notes to DPL’s Consolidated Financial Statements and Note 9 – Benefit Plans of Notes to DP&L’s Financial Statements for more information.

Contingent and Other Obligations
During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We believe such estimates and assumptions are reasonable.

Recently Issued Accounting Pronouncements
A discussion of recently issued accounting pronouncements is in Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DPL’s Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L’s Financial Statements and such discussion is incorporated by reference in this Management's Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

LEGAL AND OTHER MATTERS

Discussions of legal and other matters are provided in Item 1 – Business "Environmental Matters", Item 1 – Business "Competition and Regulation" and Item 3 – Legal Proceedings. Such discussions are incorporated by reference in this Management's Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

Item 7A – Quantitative and Qualitative Disclosures about Market Risk
We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emission allowances, and 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 related 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 stations, 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. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis and where applicable, we recognize a corresponding regulatory asset for above-market costs or a regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.

The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our sales requirements for 2017 under contract, power sales obligations may change. The contracted coal is purchased at fixed prices. 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 electric generation station mix.

In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), signed into law in July 2010, contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us.

For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements 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 natural gas, 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 counterparty 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. At December 31, 2016, there are no coal derivatives.

A 10% increase or decrease in the market price of our FTRs and natural gas futures at December 31, 2016 would not have a significant effect on Net income.

At December 31, 2016, a 10% increase or decrease in the market price of our forward power contracts would result in an impact on unrealized gains/losses of $1.1 million.

Wholesale revenues
Energy not used to meet the needs of retail customers through the competitive bid process of DP&L or other utilities, is sold in the wholesale market when we can identify opportunities with positive margins. For years prior to 2016, energy in excess of the needs of existing retail customers was sold into the wholesale market and DP&L’s electric revenues in the wholesale market included sales to DPLER.

Approximately 43% of DPL’s and 42% of DP&L’s electric revenues during the year ended December 31, 2016 were from sales of excess energy and capacity in the wholesale market.


Approximately 46% of DPL’s and 45% of DP&L’s electric revenues during the year ended December 31, 2015 were from sales of excess energy and capacity in the wholesale market.

Approximately 46% of DPL’s and 45% of DP&L’s electric revenues during the year ended December 31, 2014 were from sales of excess energy and capacity in the wholesale market.

The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2016 of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power, including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale:
$ in millions DPL DP&L
Effect of 10% change in price per MWh $24.6
 $19.2

Capacity revenues and costs
As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year that runs from June 1 to May 31, has conducted auctions for capacity through the 2019/20 delivery year. The clearing prices for capacity during the PJM delivery periods from 2015/16 through 2019/20 are as follows:
($/MW-day) PJM Delivery Year
  2015/16 2016/17 2017/18 2018/19 2019/20
Capacity clearing price $136
 $134
 $152
 $165
 $100

Our computed average capacity prices by calendar year are reflected in the table below:
  Calendar Year
($/MW-day) 2015 2016 2017 2018 2019
Computed average capacity price $132
 $135
 $145
 $159
 $127

The above tables reflect the capacity prices after the transitional auctions discussed earlier. Substantially all of DP&L's capacity cleared in the CP auction. The results of these auctions could have a significant effect on DP&L's revenues in the future.

Future capacity 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 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.

The table below provides estimates of the effect on annual Net income (net of an estimated income tax of 35%) as of December 31, 2016 of a hypothetical increase or decrease of $10/MW-day in the capacity auction price. The table shows the impact resulting from capacity revenue changes.
$ in millions DPL DP&L
Effect of $10/MW-day change in capacity auction pricing $5.9
 $4.9

Capacity revenues and costs are also impacted by, among other factors, 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.

As approved, the CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours”. This linkage between non- or under-performance during certain specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net Cost of New Entry, which is a value computed by PJM. This level is likely to be larger than the capacity

price established under the CP program, so that the potential exists that participation in the CP program could result in capacity penalties that exceed capacity revenues.

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 years ended December 31, 2016, 2015 and 2014 were 41%, 59% and 42%, respectively. We have a significant portion of projected 2017 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2 allowances for 2017; however, the exact consumption of SO2 allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOX allowances for 2017 depending on NOX emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and electric generation station 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.

The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2016, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power:
$ in millions DPL DP&L
Effect of 10% change in fuel and purchased power $44.6
 $43.1

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 $125 million secured term loan with a syndicated bank group. DP&L’s variable-rate debt is comprised of $200 million of bank held tax-exempt First Mortgage Bonds and $445.0 million Term Loan B debt secured by First Mortgage Bonds. Each variable-rate bond bears interest based on an underlying interest rate index, typically LIBOR. On November 21, 2016, the DP&L $200.0 million variable-rate First Mortgage Bonds were hedged with fixed for floating rate interest rate swaps, reducing interest rate risk exposure for the term of the bonds. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 8 – Debt of Notes to DPL’s Consolidated Financial Statements and Note 7 – Debt of Notes to DP&L’s Financial Statements.

Principal payments and interest rate detail by contractual maturity date
The principal amount of DPL’s debt was $1,883.6 million at December 31, 2016, consisting of DPL’s unsecured notes, secured term loan, Capital Trust II securities along with DP&L’s First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. All of DPL’s existing debt was adjusted to fair value at the Merger date according to FASB Accounting Standards Codification No. 805, “Business Combinations”. The fair value of this debt at December 31, 2016 was $1,907.7 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:


DPL Years ending December 31,   Principal amount at December 31, Fair value at December 31,
$ in millions 2017 2018 2019 2020 2021 Thereafter 2016 2016
Long-term debt (a)
                
Variable-rate debt $29.5
 $29.5
 $29.5
 $54.6
 $4.5
 $422.4
 $570.0
 $570.0
                 
Average interest rate 3.2% 3.2% 3.2% 3.1% 4.0% 4.0%    
                 
Fixed-rate debt (b)
 $0.1
 $0.1
 $200.2
 $200.2
 $780.2
 $132.8
 1,313.6
 1,337.7
                 
Average interest rate 4.2% 3.2% 6.7% 2.0% 7.2% 5.1%    
                 
Total             $1,883.6
 $1,907.7
(a)Amounts exclude immaterial capital lease obligations
(b)
Fixed-rate debt includes $200.0 million DP&L Tax-exempt First Mortgage Bonds that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities

The principal amount of DP&L’s debt was $763.0 million at December 31, 2016, consisting of its First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. The fair value of this debt at December 31, 2016 was $763.5 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. The DP&L debt was not revalued using push-down accounting as a result of the Merger.

DP&L Years ending December 31,   Principal amount at December 31, Fair value at December 31,
$ in millions 2017 2018 2019 2020 2021 Thereafter 2016 2016
Long-term debt (a)
                
Variable-rate debt $4.5
 $4.5
 $4.5
 $4.5
 $4.5
 $422.5
 $445.0
 $445.0
                 
Average interest rate 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%    
                 
Fixed-rate debt (b)
 $0.1
 $0.1
 $0.2
 $200.2
 $0.2
 $117.2
 318.0
 318.5
                 
Average interest rate 4.2% 4.2% 4.2% 2.0% 4.2% 4.7%    
                 
Total             $763.0
 $763.5
(a)Amounts exclude immaterial capital lease obligations
(b)
Fixed-rate debt includes $200.0 million DP&L Tax-exempt First Mortgage Bonds that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities

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 December 31, 2016 and 2015 for which an immediate adverse market movement causes a potential material effect 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. At December 31, 2016 and 2015, we did not hold any market risk sensitive instruments which were entered into for trading purposes.


Principal value and fair value of debt with one percent interest rate risk
DPL            
$ in millions Principal amount at December 31, 2016 Fair value at December 31, 2016 One Percent
Interest Rate
Risk		 Principal amount at December 31, 2015 Fair value at December 31, 2015 One Percent
Interest Rate
Risk
Long-term debt (a)
            
Variable-rate debt $570.0
 $570.0
 $5.7
 $325.0
 $325.0
 $3.3
             
Fixed-rate debt (b) 1,313.6
 1,337.7
 13.4
 1,684.4
 1,650.3
 16.5
             
Total $1,883.6
 $1,907.7
 $19.1
 $2,009.4
 $1,975.3
 $19.8

(a)Amounts exclude immaterial capital lease obligations
(b)
Fixed-rate debt includes $200.0 million DP&L Tax-exempt First Mortgage Bonds that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities
DP&L            
$ in millions Principal amount at December 31, 2016 Fair value at December 31, 2016 One Percent
Interest Rate
Risk		 Principal amount at December 31, 2015 Fair value at December 31, 2015 One Percent
Interest Rate
Risk
Long-term debt (a)
            
Variable-rate debt $445.0
 $445.0
 $4.5
 $200.0
 $200.0
 $2.0
             
Fixed-rate debt (b) 318.0
 318.5
 3.2
 562.9
 564.2
 5.6
             
Total $763.0
 $763.5
 $7.7
 $762.9
 $764.2
 $7.6

(a)Amounts exclude immaterial capital lease obligations
(b)
Fixed-rate debt includes $200.0 million DP&L Tax-exempt First Mortgage Bonds that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $1,337.7 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 $570.0 million variable-rate long-term debt outstanding at December 31, 2016.

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 $318.5 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 $445.0 million variable-rate long-term debt outstanding at December 31, 2016.

Equity price risk
At December 31, 2016, approximately 37% of the defined benefit pension plan assets were comprised of investments in equity securities and 63% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. The equity securities are carried at their market value of approximately $125.8 million at December 31, 2016. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12.6 million reduction in fair value at December 31, 2016 and approximately a $0.6 million increase to the 2017 pension expense.

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 counterparties on an ongoing basis. We may require various forms of credit assurance from counterparties in order to mitigate credit risk.

Item 8 – Financial Statements and Supplementary Data
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 clearly be noted in the section.


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FINANCIAL STATEMENTS

DPL INC.

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Report of Independent Registered Public Accounting Firm

To theThe Board of Directors of DPL Inc.

We have audited the accompanying consolidated balance sheets of DPL Inc. as of December 31, 20152016 and 2014,2015, and the related consolidated statements of operations, comprehensive income/(loss),loss, cash flows and shareholder’s equity for each of the three years in the period ended December 31, 2015.2016. Our audits also included the financial statement schedule “Schedule II - Valuation and Qualifying Accounts” for each of the three years in the period ended December 31, 2015.2016. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our auditsDecember 31, 2016 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. We conducted our December 31, 2015 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,statements. An audit also includes assessing the accounting principles used and significant estimates made by management, andas well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of DPL Inc. at December 31, 20152016 and 2014,2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.


/s/ Ernst & Young LLP

February 23, 2016
Indianapolis, Indiana
February 24, 2017


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DPL INC.CONSOLIDATED STATEMENTS OF OPERATIONS
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Revenues $1,612.8
 $1,716.5
 $1,579.0
 $1,427.3
 $1,612.8
 $1,716.5
Cost of revenues:            
Fuel 259.8
 304.5
 366.7
 268.8
 259.8
 304.5
Purchased power 562.6
 587.9
 383.0
 417.4
 562.6
 587.9
Total cost of revenues 822.4
 892.4
 749.7
 686.2
 822.4
 892.4
      
Gross margin 790.4
 824.1
 829.3
 741.1
 790.4
 824.1
Operating expenses:            
Operation and maintenance 361.3
 362.4
 365.7
 348.1
 361.3
 362.4
Depreciation and amortization 134.6
 135.6
 129.2
 132.3
 134.6
 135.6
General taxes 87.0
 87.8
 76.8
 85.7
 87.0
 87.8
Goodwill impairment 317.0
 —
 306.3
Fixed-asset impairment —
 11.5
 26.2
Goodwill impairment (Note 7) —
 317.0
 —
Fixed-asset impairment (Note 15) 859.0
 —
 11.5
Other 0.4
 (3.9) 2.5
 (0.1) 0.4
 (3.9)
Total operating expenses 900.3
 593.4
 906.7
 1,425.0
 900.3
 593.4
            
Operating income / (loss) (109.9) 230.7
 (77.4) (683.9) (109.9) 230.7
            
Other income / (expense), net            
Investment income 0.2
 0.9
 1.4
 0.4
 0.2
 0.9
Interest expense (118.3) (126.6) (124.0) (106.1) (118.3) (126.6)
Charge for early redemption of debt (2.1) (30.9) (2.8) (3.1) (2.1) (30.9)
Other deductions (1.3) (1.5) (3.0) (0.6) (1.3) (1.5)
Other expense, net (121.5) (158.1) (128.4) (109.4) (121.5) (158.1)
            
Earnings (loss) from continuing operations before income tax (231.4) 72.6
 (205.8)
Income / (loss) from continuing operations before income tax (793.3) (231.4) 72.6
            
Income tax expense from continuing operations 20.0
 15.4
 19.8
Income tax expense / (benefit) from continuing operations (278.8) 20.0
 15.4
            
Net income / (loss) from continuing operations (251.4) 57.2
 (225.6) (514.5) (251.4) 57.2
            
Discontinued operations (Note 16)            
Income / (loss) from discontinued operations 11.4
 (129.2) 6.0
 (0.7) 11.4
 (129.2)
Gain from disposal of discontinued operations 49.2
 —
 —
Income tax expense / (benefit) (1.0) 2.6
 2.4
 19.2
 (1.0) 2.6
Discontinued operations 12.4
 (131.8) 3.6
Net income / (loss) from discontinued operations 29.3
 12.4
 (131.8)
            
Net loss $(239.0) $(74.6) $(222.0) $(485.2) $(239.0) $(74.6)

See Notes to Consolidated Financial Statements.


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DPL INC.
STATEMENTS OF COMPREHENSIVE LOSS
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSSCONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Net loss $(239.0) $(74.6) $(222.0) $(485.2) $(239.0) $(74.6)
Available-for-sale securities activity:            
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.1, $0.2 and $0.6 for each respective period (0.1) (0.3) (1.2)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, ($0.2) and ($0.7) for each respective period —
 0.2
 1.4
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of ($0.1), $0.1 and $0.2 for each respective period 0.2
 (0.1) (0.3)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, $0.0 and ($0.2) for each respective period —
 —
 0.2
Total change in fair value of available-for-sale securities (0.1) (0.1) 0.2
 0.2
 (0.1) (0.1)
Derivative activity:            
Change in derivative fair value, net of income tax benefit / (expense) of ($10.3), $10.3 and ($10.6) for each respective period 18.2
 (19.0) 19.7
Reclassification to earnings, net of income tax benefit / (expense) of $5.4, ($9.5) and ($2.3) for each respective period (10.0) 16.9
 3.4
Change in derivative fair value, net of income tax benefit / (expense) of ($8.8), ($10.3) and $10.3 for each respective period 16.1
 18.2
 (19.0)
Reclassification to earnings, net of income tax benefit / (expense) of $16.7, $5.4 and ($9.5) for each respective period (29.7) (10.0) 16.9
Total change in fair value of derivatives 8.2
 (2.1) 23.1
 (13.6) 8.2
 (2.1)
Pension and postretirement activity:            
Prior service cost for the period, net of income tax benefit / (expense) of $0.0, $1.3 and $0.0 for each respective period —
 (2.2) —
Net gain / (loss) for the period, net of income tax benefit / (expense) of ($1.2), $7.1 and ($2.7) for each respective period 1.6
 (12.7) 4.9
Reclassification to earnings, net of income tax benefit / (expense) of ($0.2), $0.0 and $0.3 for each respective period 0.2
 —
 0.3
Total change in unfunded pension and postretirement 1.8
 (14.9) 5.2
Prior service cost for the period, net of income tax benefit / (expense) of $0.0, $0.0 and $1.3 for each respective period —
 —
 (2.2)
Net gain / (loss) for the period, net of income tax benefit / (expense) of $2.4, ($1.2) and $7.1 for each respective period (4.7) 1.6
 (12.7)
Reclassification to earnings, net of income tax benefit / (expense) of ($0.6), ($0.2) and $0.0 for each respective period 1.0
 0.2
 —
Total change in unfunded pension and postretirement obligations (3.7) 1.8
 (14.9)
            
Other comprehensive income / (loss) 9.9
 (17.1) 28.5
 (17.1) 9.9
 (17.1)
            
Net comprehensive loss $(229.1) $(91.7) $(193.5) $(502.3) $(229.1) $(91.7)

See Notes to Consolidated Financial Statements.

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DPL INC.CONSOLIDATED BALANCE SHEETS
$ in millions December 31, 2015 December 31, 2014 December 31, 2016 December 31, 2015
ASSETS        
Current assets:        
Cash and cash equivalents $32.4
 $17.0
 $54.6
 $32.4
Restricted cash 92.7
 16.8
 29.0
 92.7
Accounts receivable, net (Note 2) 120.9
 136.5
 135.1
 120.9
Inventories (Note 2) 109.1
 100.2
 77.2
 109.1
Taxes applicable to subsequent years 81.2
 77.8
 81.0
 81.2
Regulatory assets, current (Note 3) 14.4
 44.2
 0.1
 14.4
Other prepayments and current assets 46.6
 38.9
 31.8
 44.5
Assets held for sale - current (Note 16) 62.2
 67.3
 —
 62.2
Total current assets 559.5
 498.7
 408.8
 557.4
        
Property, plant and equipment:        
Property, plant and equipment 2,909.0
 2,754.1
 1,985.6
 2,850.7
Less: Accumulated depreciation and amortization (432.3) (317.9) (334.8) (397.0)
 2,476.7
 2,436.2
 1,650.8
 2,453.7
Construction work in process 85.0
 76.4
 116.4
 83.5
Total net property, plant and equipment 2,561.7
 2,512.6
 1,767.2
 2,537.2
Other non-current assets:        
Regulatory assets, non-current (Note 3) 179.9
 167.5
 203.9
 179.9
Goodwill (Note 7) —
 317.0
Intangible assets, net of amortization (Note 7) 5.0
 7.8
Intangible assets, net of amortization 22.7
 29.5
Other deferred assets 34.7
 39.7
 16.6
 20.7
Assets held for sale - non-current (Note 16) —
 34.5
Total other non-current assets 219.6
 566.5
 243.2
 230.1
        
Total Assets $3,340.8
 $3,577.8
 $2,419.2
 $3,324.7
        
LIABILITIES AND SHAREHOLDER'S EQUITY        
Current liabilities:        
Current portion - long-term debt (Note 8) $574.9
 $20.1
 $29.7
 $572.8
Accounts payable 97.5
 94.4
 113.9
 97.5
Accrued taxes 142.4
 102.6
 185.1
 142.4
Accrued interest 21.4
 27.2
 17.7
 21.4
Customer security deposits 15.2
 14.4
 15.2
 15.2
Regulatory liabilities, current (Note 3) 24.4
 4.4
 33.7
 24.4
Insurance and claims costs 5.9
 6.4
 5.4
 5.9
Other current liabilities 54.5
 46.3
 50.2
 54.5
Deposit received on sale of DPLER (Note 16) 75.5
 —
 —
 75.5
Liabilities held for sale - current (Note 16) 1.6
 17.1
 —
 1.6
Total current liabilities 1,013.3
 332.9
 450.9
 1,011.2
Non-current liabilities:        
Long-term debt (Note 8) 1,434.5
 2,139.6
 1,828.7
 1,420.5
Deferred taxes (Note 9) 568.7
 587.3
 252.4
 568.7
Taxes payable 84.1
 80.7
 84.6
 84.1
Regulatory liabilities, non-current (Note 3) 127.0
 124.1
 130.4
 127.0
Pension, retiree and other benefits (Note 10) 87.1
 95.9
 101.6
 87.1
Asset retirement obligations 138.8
 65.9
Other deferred credits 88.3
 50.5
 19.4
 22.4
Liabilities held for sale - non-current (Note 16) —
 0.2
Total non-current liabilities 2,389.7
 3,078.3
 2,555.9
 2,375.7
        
Redeemable preferred stock of subsidiary (Note 11) 18.4
 18.4
 —
 18.4
        
Commitments and contingencies (Note 12) 
 
 
 
        
Common shareholder's equity:        
Common stock:        
1,500 shares authorized; 1 share issued and outstanding        
at December 31, 2015 and 2014 —
 —
at December 31, 2016 and 2015 —
 —
Other paid-in capital 2,237.7
 2,237.4
 2,233.0
 2,237.7
Accumulated other comprehensive income 17.4
 7.5
 0.3
 17.4
Retained earnings / (deficit) (2,335.7) (2,096.7)
Accumulated deficit (2,820.9) (2,335.7)
Total common shareholder's equity (80.6) 148.2
 (587.6) (80.6)
        
Total Liabilities and Shareholder's Equity $3,340.8
 $3,577.8
 $2,419.2
 $3,324.7

See Notes to Consolidated Financial Statements.

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Table of Contents

DPL INC.CONSOLIDATED STATEMENTS OF CASH FLOWS
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Cash flows from operating activities:            
Net loss $(239.0) $(74.6) $(222.0) $(485.2) $(239.0) $(74.6)
Adjustments to reconcile Net loss to Net cash from operating activities            
Depreciation and amortization 138.8
 139.8
 132.9
 132.3
 138.8
 139.8
Amortization of intangibles —
 1.2
 7.1
 —
 —
 1.2
Amortization of debt market value adjustments (1.1) 0.3
 (14.4) 0.1
 (1.1) 0.3
Amortization of deferred financing costs 5.9
 6.3
 5.0
 5.6
 5.9
 6.3
Unrealized loss on derivatives 5.8
 3.0
 5.9
Unrealized (gain) / loss on derivatives (4.3) 5.8
 3.0
Deferred income taxes (17.1) 17.7
 24.0
 (306.2) (17.1) 17.7
Charge for early redemption of debt 2.1
 30.9
 2.8
 3.1
 2.1
 30.9
Goodwill impairment (a)
 317.0
 135.8
 306.3
 —
 317.0
 135.8
Fixed-asset impairment —
 11.5
 26.2
 859.0
 —
 11.5
Loss / (Gain) on asset disposal 0.4
 (3.9) 2.5
 (49.2) 0.4
 (3.9)
Changes in certain assets and liabilities:            
Accounts receivable 43.4
 0.5
 7.4
 24.2
 43.4
 0.5
Inventories (9.0) (24.9) 27.4
 32.0
 (9.0) (24.9)
Prepaid taxes (1.3) (0.9) 0.7
 0.2
 (1.3) (0.9)
Taxes applicable to subsequent years (3.4) (7.1) (1.4) 0.2
 (3.4) (7.1)
Deferred regulatory costs, net 21.8
 5.4
 7.6
 4.1
 21.8
 5.4
Accounts payable (5.1) 32.1
 (5.8) 16.5
 (5.1) 32.1
Accrued taxes payable 43.8
 20.7
 (5.5) 45.1
 43.8
 20.7
Accrued interest payable (5.7) (1.3) (3.3) (3.7) (5.7) (1.3)
Other current and deferred liabilities (10.4) (40.6) 1.5
 (4.0) (10.4) (40.6)
Pension, retiree and other benefits (0.7) 19.1
 1.8
 8.6
 (0.7) 19.1
Unamortized investment tax credit (0.5) (0.5) (0.5) (0.4) (0.5) (0.5)
Insurance and claims costs (0.5) (0.2) (4.8) (0.5) (0.5) (0.2)
Other 23.3
 (26.2) 1.4
 (10.4) 23.3
 (26.2)
Net cash from operating activities 308.5
 244.1
 302.8
Net cash provided by operating activities 267.1
 308.5
 244.1
            
Cash flows from investing activities:            
Capital expenditures (137.2) (118.1) (124.4) (148.5) (137.2) (118.1)
Proceeds from sale of property 1.3
 10.7
 0.8
Proceeds from sale of business 75.5
 1.3
 10.7
Insurance proceeds —
 0.3
 7.6
 6.3
 —
 0.3
Purchase of renewable energy credits (0.8) (3.5) (3.9) (0.4) (0.8) (3.5)
Decrease / (increase) in restricted cash (0.4) (3.3) (2.8)
Increase in restricted cash (11.8) (0.4) (3.3)
Other investing activities, net 0.4
 1.3
 (1.2) 1.1
 0.4
 1.3
Net cash from investing activities (136.7) (112.6) (123.9)
Net cash used in investing activities (77.8) (136.7) (112.6)
            
Cash flows from financing activities:            
Deferred financing costs (6.9) (3.6) (15.3)
Payments of deferred financing costs (8.6) (6.9) (3.6)
Redemption of preferred stock (23.5) —
 —
Retirement of debt (474.5) (335.0) (945.1) (577.8) (474.5) (335.0)
Premium paid for early redemption of debt —
 (29.1) (2.4) —
 —
 (29.1)
Issuance of long-term debt 325.0
 200.0
 645.0
Issuance of long-term debt, net of discount 442.8
 325.0
 200.0
Borrowings from revolving credit facilities 80.0
 190.0
 50.0
 15.0
 80.0
 190.0
Repayment of borrowings from revolving credit facilities (80.0) (190.0) (50.0) (15.0) (80.0) (190.0)
Net cash from financing activities (156.4) (167.7) (317.8)
Net cash used in financing activities (167.1) (156.4) (167.7)
            
Cash and cash equivalents:            
Net increase / (decrease) in cash 15.4
 (36.2) (138.9) 22.2
 15.4
 (36.2)
Balance at beginning of period 17.0
 53.2
 192.1
 32.4
 17.0
 53.2
Cash and cash equivalents at end of period $32.4
 $17.0
 $53.2
 $54.6
 $32.4
 $17.0
Supplemental cash flow information:            
Interest paid, net of amounts capitalized $111.6
 $117.3
 $137.5
 $103.8
 $111.6
 $117.3
Income taxes paid / (refunded), net $0.8
 $0.7
 $(5.2) $0.3
 $0.8
 $0.7
Non-cash financing and investing activities:            
Accruals for capital expenditures $18.6
 $16.3
 $14.7
 $16.2
 $18.6
 $16.3
(a)Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations.

See Notes to Consolidated Financial Statements.

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DPL INC.CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
Common Stock (a)
 
Common Stock (a)
 
$ in millions (except Outstanding Shares)Outstanding SharesAmount
Other
Paid-in
Capital
Accumulated Other Comprehensive Income / (Loss)
Retained Earnings/
(Deficit)
TotalOutstanding SharesAmount
Other
Paid-in
Capital
Accumulated Other Comprehensive Income / (Loss)Accumulated deficitTotal
Year ended December 31, 2013  
Year ended December 31, 2014  
Beginning balance1
$—
$2,236.7
$(3.9)$(1,806.0)$426.8
1
$—
$2,237.0
$24.6
$(2,022.1)$239.5
Net comprehensive loss  28.5
(222.0)(193.5)
Common stock dividends  —
—
Other (b)
  0.3
 5.9
6.2
Ending balance1
—
2,237.0
24.6
(2,022.1)239.5
Year ended December 31, 2014  
Net comprehensive loss  (17.1)(74.6)(91.7)  (17.1)(74.6)(91.7)
Other  0.4
 —
0.4
  0.4
—
—
0.4
Ending balance1
—
2,237.4
7.5
(2,096.7)148.2
1
—
2,237.4
7.5
(2,096.7)148.2
Year ended December 31, 2015    
Net comprehensive loss  9.9
(239.0)(229.1)  9.9
(239.0)(229.1)
Other  0.3
 

0.3
  0.3
—
—
0.3
Ending balance1
$—
$2,237.7
$17.4
$(2,335.7)$(80.6)1
—
2,237.7
17.4
(2,335.7)(80.6)
Year ended December 31, 2016  
Net comprehensive loss  (17.1)(485.2)(502.3)
Other (b)
  (4.7)—
—
(4.7)
Ending balance1
$—
$2,233.0
$0.3
$(2,820.9)$(587.6)

(a)1,500 shares authorized
(b)
$5.95.1 million was charged to Other paid-in capital for the redemption of dividends declared in 2012 were reversed in 2013.the DP&L preferred shares. See Note 11 – Equity.

See Notes to Consolidated Financial Statements.

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Table of Contents

DPL Inc.
Notes to Consolidated Financial Statements
For the years ended December 31, 2016, 2015 2014 and 20132014

Note 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’sDPL onehas two reportable segments, the Transmission and Distribution ("T&D") segment isand the UtilityGeneration segment comprised of its DP&L. subsidiary. See Note 14 – Business Segments for more information relating to reportable segments. The terms “we”, “us”, “our” and “ours” are used to refer to DPL and its subsidiaries.

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

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribution and transmission services are still regulated. DP&L has the exclusive right to provide such service to its approximately 517,000519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer supplied 100%January 2016, all of the generationelectric supply for SSO customers and starting January 2016, SSO is now 100% competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the generalgeneral economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. Through December 31, 2015, DP&L&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of itsDPLER's retail customers.

In accordance with the ESP Order, onOn December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014, the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L is required to sell or transfer its generation assets by January 1, 2017 and continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale.

DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER had approximately 125,000 customers located throughout Ohio. DPLER’s operations included those of its wholly-owned subsidiary MC Squared through April 1, 2015, when DPLER sold MC Squared. Approximately 110,000 of DPLER’s customers were also electric distribution customers of DP&L. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the area. See Note 16 – Discontinued Operations for more information.

DPL’s other significant subsidiaries include DPLE,AES Ohio Generation, 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 other subsidiaries. Effective February 1, 2016, DPLE was renamed AES Ohio Generation, LLC. DPL owns all of the common stock of its subsidiaries.

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

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


18
Table of Contents

DPL and its subsidiaries employed 1,2191,168 people at January 31, 2016,2017, of which 1,1891,160 were employed by DP&L. Approximately 60%62% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2017.


Financial Statement Presentation
We prepare Consolidated Financial Statements for DPL. DPL’s 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 stations are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 4 – Property, Plant and Equipment for more information.

All material intercompany accounts and transactions are eliminated in consolidation. We have evaluated subsequent events through the date this report is issued.

Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation. See “Intangibles” below for additional information.

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

Valuation of Goodwill
FASC 350, “Intangibles – Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. See Note 7 – Goodwill and Other Intangible Assets for information regarding the impairmentsimpairment of goodwill in 2015 2014 and 2013.2014.

Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.

All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.

19


Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.0$2.8 million, $1.5$2.0 million and $1.5 million in the years ended December 31, 2016, 2015 2014 and 2013,2014, respectively.

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

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

Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. See Note 15 – Fixed-asset Impairment for more information.

Repairs and Maintenance
Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 4.6%6.1% in 2016, 4.4% in 2015 and 5.3% in 2014 and 5.8% in 2013.2014. Depreciation expense was $121.9 million, $125.9 million $128.1 million and $120.9$128.1 million for the years ended December 31, 2016, 2015 2014 and 2013,2014, respectively.

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

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

Inventories
Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.


20

Intangibles
Intangibles include software, 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 cost 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 on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired.

Intangible assets include capitalized software of $65.1 million and $59.9 million and its corresponding amortization of $43.2 million and $35.3 million previously classified within Total net property, plant and equipment that were reclassified to Intangible assets as of December 31, 2016 and 2015, respectively. These assets are amortized over seven years. See Note 7 – Goodwill and Other Intangible Assets“New Accounting Pronouncements” below for additional information. Amortization expense was $7.7 million, $9.0 million and $8.6 million for the years ended December 31, 2016, 2015 and 2014, respectively. The estimated amortization expense of this internal-use software is $15.3 million ($6.1 million in 2017, $5.6 million in 2018 and $3.6 million in 2019).

Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statement of Operations.

Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Assets and LiabilitiesMatters for additional information.

DPLand its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 9 – Income Taxes for additional information.

Financial Instruments
We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’shareholder's equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2016, 2015 and 2014, and 2013, were $50.9 million, $49.9 million $50.8 million and $50.5$50.8 million, respectively.

Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash

also includes cash received in connection with the sale of DPLER on January 1, 2016. See Note 16 – Discontinued Operations for additional information regarding the sale of DPLER.

Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.


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We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information.

Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $5.9$5.4 million and $6.4$5.9 million at December 31, 20152016 and 2014,2015, respectively. In addition, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and disabilityother reserves for claims costs below certain coverage thresholds of third-party providers of approximately $13.7$12.0 million and $15.6$13.7 million at December 31, 20152016 and 2014,2015, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Pension and Postretirement Benefits
We recognize, in our Consolidated Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

Effective January 1, 2016, we will applyapplied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of ASCFASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.

The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015 or 2016, nor will it impact future remeasurements. This change in approach will impactimpacted the service cost and interest cost recorded in 2016 and will impact future years. It will also impactimpacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof.


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The expected 2016 service costs and interest costs included in Note 10 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on expected service costs and interest costs in 2016 is shown below:
$ in millions Expected 2016 Service Cost Expected 2016 Interest Cost 2016 Service Cost 2016 Interest Cost
 Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change
Total Pension $5.7
 $6.1
 $(0.4) $14.8
 $17.9
 $(3.1) $5.7
 $6.1
 $(0.4) $14.7
 $17.9
 $(3.2)
Total Postretirement Benefits $0.2
 $0.2
 $—
 $0.6
 $0.7
 $(0.1) 0.2
 0.2
 —
 0.6
 0.7
 (0.1)
Total $5.9
 $6.3
 $(0.4) $15.4
 $18.6
 $(3.2) $5.9
 $6.3
 $(0.4) $15.3
 $18.6
 $(3.3)

See Note 10 – Benefit Plans for more information.

Related Party Transactions
In the normal course of business, DPL enters into transactions with related parties. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements.

See Note 13 – Related Party Transactions for more information on Related Party Transactions.

DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 20152016 and 2014,2015, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 20152016 and December 31, 2014,2015, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – Debt for additional information.

In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.

New accounting pronouncements adopted

ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet ClassificationThe following table provides a brief description of Deferred Taxes
Effective December 31, 2015, we prospectively adopted ASU No. 2015-17, which requiresrecent accounting pronouncements that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As we elected to apply this ASU prospectively, prior periods were not adjusted.

ASU No. 2015-13, Derivatives and Hedging (Topic 815):Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Market
In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815, Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As we had designated qualifying contracts as normal purchase or normal sales, there was no impact on our financial statements upon adoption of this standard.


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Accounting pronouncements issued but not yet effective

ASU No. 2016-01, Financial Instruments — Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. We are currently evaluating the applicability and materiality of the standard, but we do not anticipate a material impact on our consolidated financial statements.

ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. We will adopt this standard on January 1, 2016, which is not expected tocould have a material impact on our consolidated financial statements.statements:
Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Adopted
2016-19 - Technical Corrections and Improvements
This standard clarifies guidance that affects the implementation of ASU 2015-05. It clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition method: retrospective.

The adoption of the new guidance did not have an impact on net income, net assets or net equity.		December 31, 2016Capitalized software of $59.9 million and its corresponding amortization of $35.3 million previously classified within property, plant and equipment were reclassified to intangibles as of December 31, 2015.
2015-15, Interest - Imputation of Interest (Subtopic 835-30)Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.January 1, 2016Deferred financing costs related to lines-of-credit of approximately $3.1 million recorded within Other deferred assets were not reclassified.

ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30)
In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, DPL had approximately $16.1 million in deferred financing costs classified in other current and other non-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.
Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
2015-03, Interest - Imputation of Interest (Subtopic 835-30)The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.January 1, 2016Deferred financing costs of approximately $2.1 million previously classified within Other prepayments and current assets and $14.0 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.
2015-02, Consolidation (Topic 810): Amendments to the Consolidation AnalysisThe standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.January 1, 2016There were no changes to the consolidation conclusions.
2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40)The standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.December 31, 2016Adoption of this standard had no impact on our consolidated financial statements.
New Accounting Standards Issued But Not Yet Effective
2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill ImpairmentThis standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value.January 1, 2020. Early adoption is permitted as of January 1, 2017.We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a BusinessThis standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business.January 1, 2018. Early adoption is permittedWe are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.January 1, 2018 Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-17, Consolidation (Topic 810): Interest Held Through Related Parties That are Under Common ControlStates that businesses deciding whether they are primary beneficiaries can consider indirect interests held through related parties that are under common control on a proportionate basis as opposed to in their entirety.January 1, 2017 Early adoption is permitted.Transition is retrospective to all relevant prior periods beginning with the fiscal year in which ASU 2015-02 was initially applied.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than InventoryThis standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.January 1, 2018. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements
In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, we had deferred financing costs related to lines of credit of approximately $3.1 million recorded within Other noncurrent assets that would not be reclassified upon adoption of this standard.
Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective.January 1, 2018. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We do not anticipate a material effect on our consolidated financial statements.
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial InstrumentsThe standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various.January 1, 2020. Early adoption is permitted only as of January 1, 2019.We are currently evaluating the impact of adopting the standard on our consolidated financial statements. No transition method has been selected yet.
2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF MeetingRemoves some of the Emerging Issues Task Force (EITF) guidance for revenue recognition and hedge accounting from U.S. GAAP to reflect announcements the SEC staff made to the task force in March.January 1, 2018. Earlier application is permitted only as of January 1, 2017.We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment AccountingThe standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.January 1, 2017. Early adoption is permitted.The primary effect of adoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt InstrumentsThis standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.January 1, 2017. Early adoption is permitted.We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting RelationshipsThe standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.January 1, 2017. Early adoption is permitted.We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements. No transition method has been selected yet.

Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
2016-02, Leases (Topic 842)The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with Topic 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.January 1, 2019. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial LiabilitiesThe standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.January 1, 2018. Limited early adoption permitted.We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our consolidated financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of InventoryThe standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.January 1, 2017. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, Revenue from Contracts with Customers (Topic 606),See discussion of the ASU below.January 1, 2018. Earlier application is permitted only as of January 1, 2017.We will adopt the standards on January 1, 2018; and we are currently evaluating the effect of their adoption on our consolidated financial statements.

ASU No. 2015-11, Inventory (Topic 330): Simplifying2014-09 and its subsequent corresponding updates provide the Measurement of Inventory
In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test.principles an entity must apply to measure and recognize revenue. The standardcore principle is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As we already used the net realizable value to make lower of cost or market determinations, there will be no impact on our financial statements upon adoption of this standard.

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ASU No. 2015-05, Intangibles – Goodwill and Other: Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. As all of our cloud computing arrangements will continue to be accounted for as service agreements, there will be no impact on our financial statements upon the adoption of this standard.

ASU No. 2014-05, Presentation of Financial Statements: Going Concern
The FASB recently issued ASU 2014-15 “Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016. ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity toshall recognize revenue to depict the transfer of promised goods or services to customers atin an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015,Amendments to the FASBstandard were issued ASU No. 2015-14, Revenue from Contract with Customers (Topic 606): Deferralthat provide further clarification of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017principle and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities).to provide certain transition expedients. The standard permitswill replace most existing revenue recognition guidance in GAAP, including the useguidance on recognizing other income upon the sale or transfer of nonfinancial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach.approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We have not yet selected a transition method and are currently evaluating the impact ofworking towards adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on ourthe final impact to the financial statements.

ASU No. 2015-02, Consolidation – AmendmentsIn 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the Consolidation Analysis (Topic 810)
In February 2015,financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB issued ASU 2015-02,and Transition Resource Group (TRG) activity, as we finalize our accounting policy on these and other industry specific interpretative issues which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the Variable Interest Entity (VIE) guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We do not expect this standard to have an impact on our financial statements upon adoption.are expected in 2017.


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Note 2 – Supplemental Financial Information

 December 31, December 31,
$ in millions 2015 2014 2016 2015
Accounts receivable, net        
Unbilled revenue $43.3
 $49.1
 $43.0
 $43.3
Customer receivables 56.4
 70.1
 73.9
 56.4
Amounts due from partners in jointly-owned stations 16.0
 15.2
 12.7
 16.0
Other 6.0
 3.0
 6.7
 6.0
Provisions for uncollectible accounts (0.8) (0.9) (1.2) (0.8)
Total accounts receivable, net $120.9
 $136.5
 $135.1
 $120.9
        
Inventories        
Fuel and limestone $72.2
 $65.3
 $38.9
 $72.2
Plant materials and supplies 34.9
 33.5
 36.6
 34.9
Other 2.0
 1.4
 1.7
 2.0
Total inventories, at average cost $109.1
 $100.2
 $77.2
 $109.1

Accounts receivable of $31.0 million and $64.4 million as of December 31, 2015 and 2014 have been excluded from the above table as they have been reclassified as "Assets held for sale". See Note 16 – Discontinued Operations.

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Accumulated Other Comprehensive Income / (Loss)
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2016, 2015 2014 and 20132014 are as follows:
Details about Accumulated Other Comprehensive Income / (Loss) Components Affected line item in the Consolidated Statements of Operations Years ended December 31, Affected line item in the Consolidated Statements of Operations Years ended December 31,
$ in millions   2015 2014 2013   2016 2015 2014
Gains and losses on Available-for-sale securities activity (Note 5):Gains and losses on Available-for-sale securities activity (Note 5):      Gains and losses on Available-for-sale securities activity (Note 5):      
 Other income / (deductions) $—
 $0.4
 $2.1
 Other income $—
 $—
 $0.4
 Tax expense —
 (0.2) (0.7) Tax expense —
 —
 (0.2)
 Net of income taxes —
 0.2
 1.4
 Net of income taxes —
 —
 0.2
            
Gains and losses on cash flow hedges (Note 6):Gains and losses on cash flow hedges (Note 6):      Gains and losses on cash flow hedges (Note 6):      
 Interest Expense (1.1) (1.3) —
 Interest Expense (1.0) (1.1) (1.3)
 Revenue (18.7) 28.4
 2.2
 Revenue (55.3) (18.7) 28.4
 Purchased power 4.4
 (0.7) 3.5
 Purchased power 9.9
 4.4
 (0.7)
 Total before income taxes (15.4) 26.4
 5.7
 Total before income taxes (46.4) (15.4) 26.4
 Tax benefit / (expense) 5.4
 (9.5) (2.3) Tax benefit / (expense) 16.7
 5.4
 (9.5)
 Net of income taxes (10.0) 16.9
 3.4
 Net of income taxes (29.7) (10.0) 16.9
            
Amortization of defined benefit pension items (Note 10):Amortization of defined benefit pension items (Note 10):      Amortization of defined benefit pension items (Note 10):      
 Operations and maintenance 0.4
 —
 —
 Operations and maintenance 1.6
 0.4
 —
 Tax expense (0.2) —
 0.3
 Tax expense (0.6) (0.2) —
 Net of income taxes 0.2
 —
 0.3
 Net of income taxes 1.0
 0.2
 —
            
Total reclassifications for the period, net of income taxesTotal reclassifications for the period, net of income taxes $(9.8) $17.1
 $5.1
Total reclassifications for the period, net of income taxes $(28.7) $(9.8) $17.1


27

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 20152016 and 20142015 are as follows:
$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance at December 31, 2013 $0.6
 $20.6
 $3.4
 $24.6
        
Other comprehensive loss before reclassifications (0.3) (19.0) (14.9) (34.2)
Amounts reclassified from accumulated other comprehensive income / (loss) 0.2
 16.9
 —
 17.1
Net current period other comprehensive loss (0.1) (2.1) (14.9) (17.1)
        
Balance at December 31, 2014 0.5
 18.5
 (11.5) 7.5
 $0.5
 $18.5
 $(11.5) $7.5
                
Other comprehensive income / (loss) before reclassifications (0.1) 18.2
 1.6
 19.7
 (0.1) 18.2
 1.6
 19.7
Amounts reclassified from accumulated other comprehensive income / (loss) —
 (10.0) 0.2
 (9.8) —
 (10.0) 0.2
 (9.8)
Net current period other comprehensive income / (loss) (0.1) 8.2
 1.8
 9.9
 (0.1) 8.2
 1.8
 9.9
                
Balance at December 31, 2015 $0.4
 $26.7
 $(9.7) $17.4
 0.4
 26.7
 (9.7) 17.4
        
Other comprehensive income / (loss) before reclassifications 0.2
 16.1
 (4.7) 11.6
Amounts reclassified from accumulated other comprehensive income / (loss) —
 (29.7) 1.0
 (28.7)
Net current period other comprehensive income / (loss) 0.2
 (13.6) (3.7) (17.1)
        
Balance at December 31, 2016 $0.6
 $13.1
 $(13.4) $0.3

Note 3 – Regulatory Assets and LiabilitiesMatters

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years supporting the alternative described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and conditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities DP&L may incur.
On January 30, 2017, DP&L, in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:
The establishment of a five-year Distribution Modernization Rider designed to collect $90.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure;
The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35.0 million in revenue per year to enable the implementation of smart grid and advanced metering ending after the fifth year of the term of the ESP;
A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC);
A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants;
A commitment to develop or procure wind and/or solar energy projects in Ohio; and
Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.


A hearing on the stipulation has been scheduled for March 8, 2017. A final decision by the PUCO is expected at the end of the second quarter or early in the third quarter of 2017. If the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh on DP&L's SSO, can expect a monthly bill increase of $2.39. There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.
In connection with any sale or exiting of our generation plants as contemplated by the ESP settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

Regulatory assets and liabilities
In accordance with FASC 980, we have recognized total regulatory assets of $194.3$204.0 million and $211.7$194.3 million at December 31, 20152016 and 2014,2015, respectively, and total regulatory liabilities of $151.4$164.1 million and $128.5$151.4 million at December 31, 20152016 and 2014,2015, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.


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The following table presents DPL’s Regulatory assets and liabilities:
     December 31,     December 31,
$ in millions Type of Recovery Amortization Through 2015 2014 Type of Recovery Amortization Through 2016 2015
Regulatory assets, current:                
Fuel and purchased power recovery costs A 2016 $13.9
 $16.3
 A 2016 $—
 $13.9
Economic development costs A 2016 0.5
 2.1
 A 2017 0.1
 0.5
Deferred storm costs B 2015 —
 22.3
Energy efficiency program A 2016 —
 1.8
Other miscellaneous A 2016 —
 1.7
Total regulatory assets, current     14.4
 44.2
     0.1
 14.4
Regulatory assets, non-current:                
Pension benefits B Ongoing $91.6
 $99.6
 B Ongoing 97.6
 91.6
Deferred recoverable income taxes B/C Ongoing 36.4
 43.1
 B/C Ongoing 35.9
 36.4
Unrecovered OVEC charges D Undetermined 21.0
 10.5
Fuel costs B Undetermined 12.7
 —
 B Undetermined 15.4
 12.7
Unrecovered OVEC charges D Undetermined 10.5
 —
Unamortized loss on reacquired debt B Various 9.0
 9.9
 B Various 8.0
 9.0
Smart grid and advanced metering infrastructure costs D Undetermined 7.3
 6.6
 D Undetermined 7.3
 7.3
Rate case costs D Undetermined 6.3
 1.9
Generation separation costs D Undetermined 3.9
 1.6
 D Undetermined 5.7
 3.9
Retail settlement system costs D Undetermined 3.1
 3.1
 D Undetermined 3.1
 3.1
Consumer education campaign D Undetermined 3.0
 3.0
 D Undetermined 3.0
 3.0
Rate case costs D Undetermined 1.9
 —
Other miscellaneous D Undetermined 0.5
 0.6
 D Undetermined 0.6
 0.5
Total regulatory assets, non-current     179.9
 167.5
     203.9
 179.9
        
Total regulatory assets $194.3
 $211.7
 $204.0
 $194.3
        
Regulatory liabilities, current:                
Competitive bidding $16.1
 $9.1
Energy efficiency program     $9.2
 $—
     14.1
 9.2
Competitive bidding 9.1
 —
Transmission costs 3.7
 2.9
 3.3
 3.7
Reconciliation rider 2.1
 —
 —
 2.1
Other miscellaneous     0.3
 1.5
     0.2
 0.3
Total regulatory liabilities, current     24.4
 4.4
     33.7
 24.4
Regulatory liabilities, non-current:                
Estimated costs of removal - regulated property     $121.8
 $119.3
     126.5
 121.8
Postretirement benefits     5.2
 4.8
     3.9
 5.2
Total regulatory liabilities, non-current     127.0
 124.1
     130.4
 127.0
        
Total regulatory liabilities $151.4
 $128.5
 $164.1
 $151.4

A – Recovery of incurred costs without aplus rate of return.
B – Recovery of incurred costs pluswithout a rate of return.
C – Balance has an offsetting liability resulting in no effect on rate base.
D – Recovery not yet determined, but is probable of occurring in future rate proceedings.

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Regulatory assets

Fuel and purchased power recovery costsrepresent 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 recoveryThis rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. As part of the PUCO approval process, an outside auditor reviews fuel costswas discontinued in 2016 and the fuel procurement process. The audit for 2014 is in process. The costs recovered throughremaining balance was transferred to the fuel rider have decreased significantly over the past three years as more SSO supply is provided through the competitive bid. While no further fuel or purchased power costs will be recoverable through the rider, it will continue for up to six months to allow for recovery of the ending deferral amount.Competitive Bid True-up rider.

Fuel costs - long-termlong term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.


Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs.

Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. All such costs have now been recovered.

Energy efficiency program costsrepresent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2014 and 2015, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million per year, after income taxes.

Pension benefitsrepresent 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.

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.

Unrecovered OVEC charges representincludes the portion of capacity charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. Because the fuel rider was discontinued in 2016, all OVEC costs, net of OVEC revenues received through PJM, are now deferred into this asset. DP&L expects to recover these costs through a future rate proceeding.

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

Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the 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. This plan is currently under development and we plan

30

to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.

Generation separation costsrepresent financing, redemption and other costs related to the divestiture of DP&L’sgeneration assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&Lrequested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending Distribution Rate Casedistribution rate case filing.

Retail settlement system costsrepresent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Consumer education campaignrepresents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.

Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Regulatory liabilities

Energy efficiency program costs see “Regulatory Assets - Energy efficiency program costs” above.

Competitive bidding represents costs associated with the development and implementation of a Competitive Bidding Process,competitive bidding process, establishing contracts to supply power for a portion of DP&L’sStandard Service Offer SSO load, as well as the net over/under recovery of the cost of the power purchased from the bid winners.

Energy efficiency program costs represent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to

recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached.On December 13, 2016 DP&L filed its Energy Efficiency portfolio case with the PUCO that specifies, among other things, that DP&L can collect lost distribution revenues for 2016 and going forward through the EER. The amount of lost revenues earned and accrued in 2016 is $20.1 million. Based on multiple parties’ agreement and past PUCO precedent on the treatment of lost distribution revenues for other utilities, it is probable, but not certain, DP&L will recover this amount. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2015 and 2016, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million after income taxes.

Transmission 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.

Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers.

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.


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Note 4 – Property, Plant and Equipment

The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 20152016 and 2014:2015:
 December 31, December 31,
$ in millions 2015 Composite Rate 2014 Composite Rate 2016 Composite Rate 2015 Composite Rate
Regulated:                
Transmission $239.4
 3.9% $227.5
 4.1% $247.3
 3.9% $239.4
 3.9%
Distribution 1,085.7
 5.0% 1,011.7
 5.4% 1,141.1
 4.7% 1,085.7
 5.0%
General 65.9
 12.4% 62.5
 12.4% 13.7
 7.4% 13.9
 7.2%
Non-depreciable 62.5
 N/A 61.6
 N/A 63.5
 N/A 62.5
 N/A
Total regulated 1,453.5
   1,363.3
   1,465.6
   1,401.5
  
Unregulated:                
Production / Generation 1,418.7
 4.2% 1,354.9
 5.4% 483.2
 11.7% 1,413.1
 4.2%
Other 17.0
 8.1% 16.1
 5.5% 17.0
 8.0% 16.3
 12.1%
Non-depreciable 19.8
 N/A 19.8
 N/A 19.8
 N/A 19.8
 N/A
Total unregulated 1,455.5
   1,390.8
   520.0
   1,449.2
  
          
Total property, plant and equipment in service $2,909.0
 4.6% $2,754.1
 5.3% $1,985.6
 6.1% $2,850.7
 4.4%

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their

respective ownership interests. At December 31, 2015,2016, DP&L had $39.0$41.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

Coal-fired facilities
DP&L’s undivided ownership interest in such facilities at December 31, 2015,2016, is as follows:
 
DP&L Share
 
DPL Carrying Value
 
DP&L Share
 
DPL Carrying Value
 
Ownership
(%)
 
Summer Production Capacity
(MW)
 
Gross Plant
In Service
($ in millions)
 
Accumulated
Depreciation
($ in millions)
 
Construction
Work in
Process
($ in millions)
 
Ownership
(%)
 
Summer Production Capacity
(MW)
 
Gross Plant
In Service
($ in millions)
 
Accumulated
Depreciation
($ in millions)
 
Construction
Work in
Process
($ in millions)
Jointly-owned production units                    
Conesville - Unit 4 16.5 129
 $26
 $4
 $1
 16.5 129
 $—
 $—
 $—
Killen - Unit 2 67.0 402
 342
 29
 2
 67.0 402
 34
 —
 2
Miami Fort - Units 7 and 8 36.0 368
 219
 32
 6
 36.0 368
 27
 —
 7
Stuart - Units 1 through 4 35.0 808
 236
 19
 18
 35.0 808
 24
 —
 23
Zimmer - Unit 1 28.1 371
 188
 44
 12
 28.1 371
 7
 —
 9
Transmission (at varying percentages)     43
 8
 —
     43
 10
 —
Total   2,078
 $1,054
 $136
 $39
   2,078
 $135
 $10
 $41


32

Each of the above generating units has SCR and FGD equipment installed.

BeckjordOn January 10, 2017, a high pressure feedwater heater shell failed on Unit 6 was retired effective October 1 2014, and DP&L’s sale of its interest in East Bend closed on December 30, 2014.at the J.M. Stuart station. As the damage assessment process is currently ongoing, we cannot determine the impact to operations or capacity at this time.

AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.

Changes in the Liability for Generation AROs
$ in millions  
Balance at December 31, 2013$24.4
Calendar 2014 
Additions3.6
Accretion expense0.9
Settlements(2.0)
Balance at December 31, 201426.9
$26.9
Calendar 2015  
Additions40.3
40.3
Accretion expense1.9
1.9
Settlements(3.2)(3.2)
Balance at December 31, 2015$65.9
65.9
Calendar 2016 
Additions70.2
Accretion expense2.7
Settlements—
Balance at December 31, 2016$138.8

See Note 5 – Fair Value for further discussion on ARO additions.

Asset Removal Costs
We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $121.8$126.5 million and $119.3$121.8 million in estimated costs of removal at December 31, 20152016 and 2014,2015, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Assets and LiabilitiesMatters for additional information.

Changes in the Liability for Transmission and Distribution Asset Removal Costs
$ in millions  
Balance at December 31, 2013$115.0
Calendar 2014 
Additions19.6
Settlements(15.3)
Balance at December 31, 2014119.3
$119.3
Calendar 2015  
Additions24.3
24.3
Settlements(21.8)(21.8)
Balance at December 31, 2015$121.8
121.8
Calendar 2016 
Additions11.7
Settlements(7.0)
Balance at December 31, 2016$126.5


33
Table of Contents


Note 5 – Fair Value

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 fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.

The table below presents the fair value and cost of our non-derivative instruments at December 31, 20152016 and 2014.2015. See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
 December 31, 2015 December 31, 2014 December 31, 2016 December 31, 2015
$ in millions Carrying Value Fair Value Carrying Value Fair Value Cost Fair Value Cost Fair Value
Assets                
Money market funds $0.2
 $0.2
 $0.1
 $0.1
 $0.4
 $0.4
 $0.2
 $0.2
Equity securities 3.0
 3.8
 2.7
 3.7
 2.4
 3.4
 3.0
 3.8
Debt securities 4.4
 4.3
 4.7
 4.7
 4.4
 4.4
 4.4
 4.3
Hedge Funds 0.4
 0.4
 0.8
 0.8
Real Estate 0.3
 0.3
 0.4
 0.4
Hedge funds —
 0.1
 0.4
 0.4
Real estate 0.3
 0.3
 0.3
 0.3
Tangible assets 0.1
 0.1
 —
 —
Total assets $8.3
 $9.0
 $8.7
 $9.7
 $7.6
 $8.7
 $8.3
 $9.0
        
 Carrying Value Fair Value Carrying Value Fair Value
Liabilities                
Debt $2,009.4
 $1,975.3
 $2,159.7
 $2,204.8
 $1,858.4
 $1,907.7
 $1,993.3
 $1,975.3

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(unadjusted 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); andor
Level 3 (unobservable inputs)inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability).

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.

We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 20152016 and 2014.2015.

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 as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 20162019 to 2061.

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


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DPL had $0.7$1.0 million ($0.50.6 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015,2016, and $0.8$0.7 million ($0.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.2015.

VariousDuring the year ended December 31, 2016, $2.6 million ($1.7 million after tax) of various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, an immaterial amount of unrealized gains were reversed into earnings. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.


The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows:
Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair Value at December 31, 2016 (a) 
Based on
Quoted Prices in
Active Markets
 
Other
observable
inputs
 Unobservable inputs
Assets        
Master trust assets        
Money market funds $0.4
 $0.4
 $—
 $—
Equity securities 3.4
 —
 3.4
 —
Debt securities 4.4
 —
 4.4
 —
Hedge funds 0.1
 —
 0.1
 —
Real estate 0.3
 —
 0.3
 —
Tangible assets 0.1
 —
 0.1
 —
Total Master trust assets 8.7
 0.4
 8.3
 —
Derivative assets        
Forward power contracts 19.5
 —
 19.5
 —
Interest rate hedge 1.2
 —
 1.2
 —
FTRs 0.1
 —
 —
 0.1
Total Derivative assets 20.8
 —
 20.7
 0.1
         
Total assets $29.5
 $0.4
 $29.0
 $0.1
Liabilities        
FTRs $—
 $—
 $—
 $—
Interest rate hedge 0.7
 —
 0.7
 —
Forward power contracts 28.5
 —
 26.0
 2.5
Total derivative liabilities 29.2
 —
 26.7
 2.5
Long-term debt 1,907.7
 —
 1,889.7
 18.0
         
Total liabilities $1,936.9
 $—
 $1,916.4
 $20.5

(a)Includes credit valuation adjustment.


The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DPL was determined as follows:
Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair Value at December 31, 2015 (a) 
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 3.8
 —
 3.8
 —
Debt securities 4.3
 —
 4.3
 —
Hedge Funds 0.4
 —
 0.4
 —
Real Estate 0.3
 —
 0.3
 —
Total Master trust assets 9.0
 0.2
 8.8
 —
Derivative assets        
Forward power contracts 30.5
 —
 30.5
 —
FTRs 0.2
 —
 —
 0.2
Total Derivative assets $30.7
 $—
 $30.5
 $0.2
         
Total assets $39.7
 $0.2
 $39.3
 $0.2
Liabilities        
FTRs 0.5
 $—
 $—
 $0.5
Forward power contracts 27.0
 —
 23.9
 3.1
Total derivative liabilities 27.5
 —
 23.9
 3.6
         
Long-term debt 1,975.3
 —
 1,957.2
 18.1
         
Total liabilities $2,002.8
 $—
 $1,981.1
 $21.7

(a)Includes credit valuation adjustment.


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The fair value of assets and liabilities at December 31, 2014 and the respective category within the fair value hierarchy for DPL was determined as follows:
Assets and Liabilities at Fair Value
   Level 1 Level 2 Level 3   Level 1 Level 2 Level 3
$ in millions Fair Value at December 31, 2014 (a) 
Based on
Quoted Prices in
Active Markets
 
Other
observable
inputs
 Unobservable inputs Fair Value at December 31, 2015 (a) 
Based on
Quoted Prices in
Active Markets
 
Other
observable
inputs
 Unobservable inputs
Assets                
Master trust assets                
Money market funds $0.1
 $0.1
 $—
 $—
 $0.2
 $0.2
 $—
 $—
Equity securities 3.7
 3.7
 —
 —
 3.8
 —
 3.8
 —
Debt securities 4.7
 4.7
 —
 —
 4.3
 —
 4.3
 —
Hedge Funds 0.8
 —
 0.8
 —
Real Estate 0.4
 0.4
 —
 —
Hedge funds 0.4
 —
 0.4
 —
Real estate 0.3
 —
 0.3
 —
Total Master trust assets 9.7
 8.9
 0.8
 —
 9.0
 0.2
 8.8
 —
                
Derivative assets                
Forward power contracts 14.9
 —
 13.7
 1.2
 30.5
 —
 30.5
 —
FTRs 0.2
 —
 —
 0.2
Total derivative assets 14.9
 —
 13.7
 1.2
 30.7
 —
 30.5
 0.2
Total assets $24.6
 $8.9
 $14.5
 $1.2
 $39.7
 $0.2
 $39.3
 $0.2
Liabilities                
FTRs $0.6
 $—
 $—
 $0.6
 $0.5
 $—
 $—
 $0.5
Heating oil futures 0.4
 0.4
 —
 —
Natural gas futures 0.1
 0.1
 —
 —
Forward power contracts 11.1
 —
 11.1
 —
 27.0
 —
 23.9
 3.1
Total derivative liabilities 12.2
 0.5
 11.1
 0.6
 27.5
 —
 23.9
 3.6
        
Long-term debt 2,204.8
 —
 2,186.6
 18.2
 1,975.3
 —
 1,957.2
 18.1
                
Total liabilities $2,217.0
 $0.5
 $2,197.7
 $18.8
 $2,002.8
 $—
 $1,981.1
 $21.7

(a)Includes credit valuation adjustment.

Our financial instruments are valued using the market approach in the following categories:
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 (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.
Level 3 inputs, such as 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. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered

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Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.

Approximately 99%94.7% 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. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $72.9 million ($47.4 million after tax) and $39.0 million ($25.4 million after tax) during the years ended December 31, 2016 and $2.52015, respectively. Increases to the AROs for the Stuart and Killen Plants totaling $67.9 million ($1.644.1 million after tax) duringwere recorded in 2016 to reflect revised estimated closure expenditures as well as plant closure dates that are earlier than previously forecast. Smaller changes were also recorded to the 12 months ended December 31, 2015 and 2014, respectively.AROs for certain other plants to reflect changes in estimated closure costs. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ($26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 – Property, Plant and Equipment for more information about AROs.

When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount.

The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
$ in millions Year ended December 31, 2015
  Carrying Fair Value Gross
  Amount Level 1 Level 2 Level 3 Loss
Goodwill (b)
          
DP&L reporting unit
 $317.0
 $—
 $—
 $—
 $317.0

$ in millions Year ended December 31, 2014
  Carrying Fair Value Gross
  Amount Level 1 Level 2 Level 3 Loss
Assets          
Long-lived assets held and used (a)
          
DP&L (East Bend)
 $14.2
 $—
 $—
 $2.7
 $11.5
Goodwill (b)
          
DPLER Reporting unit $135.8
 $—
 $—
 $—
 $135.8

$ in millions Year ended December 31, 2013
  Carrying Fair Value Gross
  Amount Level 1 Level 2 Level 3 Loss
Assets          
Long-lived assets held and used (a)
          
DP&L (Conesville)
 $26.2
 $—
 $—
 $—
 $26.2
Goodwill (b)
          
DP&L Reporting unit $623.3
 $—
 $—
 $317.0
 $306.3
  Measurement Carrying Fair Value Gross
$ in millions Date Amount Level 1 Level 2 Level 3 Loss
Long-lived assets (a)
            
    Year ended December 31, 2016
Killen December 31, 2016 $118.2
 $—
 $—
 $42.8
 $75.4
Stuart December 31, 2016 $285.9
 $—
 $—
 $57.4
 228.5
Miami Fort December 31, 2016 $185.9
 $—
 $—
 $36.5
 149.4
Zimmer December 31, 2016 $168.4
 $—
 $—
 $23.7
 144.7
Conesville December 31, 2016 $25.0
 $—
 $—
 $1.1
 23.9
Hutchings peaking facilities December 31, 2016 $3.2
 $—
 $—
 $1.6
 1.6
Killen June 30, 2016 $315.1
 $—
 $—
 $84.3
 230.8
Certain peaking facilities June 30, 2016 $9.9
 $—
 $—
 $5.2
 4.7
             
Total impairment loss           $859.0
             
    Year ended December 31, 2014
East Bend March 31, 2014 $14.2
 $—
 $—
 $2.7
 $11.5
             
Goodwill (b)
            
    Year ended December 31, 2015
DP&L reporting unit
 December 31, 2015 $317.0
 $—
 $—
 $—
 $317.0
    Year ended December 31, 2014
DPLER Reporting unit June 30, 2014 $135.8
 $—
 $—
 $—
 $135.8

(a)See Note 15 – Fixed-asset Impairment for further information
(b)See Note 7 – Goodwill and Other Intangible Assets for further information


The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016:
37
$ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average)
Long-lived assets held and used:
    Year ended December 31, 2016
Killen December 31, 2016 $42.8
 Discounted cash flow Annual revenue growth -14.2% to 2.9% (-8.0%)
        Annual pre-tax operating margin -56.6% to 42.4% (-15.5%)
        Weighted-average cost of capital 10.0%
           
Stuart December 31, 2016 $57.4
 Discounted cash flow Annual revenue growth -11.9% to 1.1% (-4.7%)
        Annual pre-tax operating margin -61.4% to 75.1% (8.0%)
        Weighted-average cost of capital 10.0%
           
Miami Fort December 31, 2016 $36.5
 Market value Indicative offer price  
           
Zimmer December 31, 2016 $23.7
 Market value Indicative offer price  
           
Conesville December 31, 2016 $1.1
 Discounted cash flow Annual revenue growth -19.3% to 10.9% (0.6%)
        Annual pre-tax operating margin -54.3% to 99.4% (20.2%)
        Weighted-average cost of capital N/A
           
Hutchings peaking facilities December 31, 2016 $1.6
 Discounted cash flow Annual revenue growth -19.5% to 25.9% (-0.7%)

       Annual pre-tax operating margin -40.3% to 63.1% (12.1%)
        Weighted-average cost of capital 7.0%
           
Killen June 30, 2016 $84.3
 Discounted cash flow Annual revenue growth -11.0% to 13.0% (2.0%)
        Annual pre-tax operating margin -50.0% to 67.0% (6.0%)
        Weighted-average cost of capital 11.0%
           
Certain peaking facilities June 30, 2016 $5.2
 Discounted cash flow Annual revenue growth -22.0% to 17.0% (-3.0%)
        Annual pre-tax operating margin -29.0% to 24.0% (-4.0%)
        Weighted-average cost of capital 7.0%

Table of Contents

Note 6 – 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 if they qualify under FASC 815 for accounting purposes.

At December 31, 2016, DPL had the following outstanding derivative instruments:
Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 2.3
 —
 2.3
Natural Gas Not designated Dths 1,590.0
 —
 1,590.0
Forward Power Contracts Designated MWh 342.9
 (9,974.5) (9,631.6)
Forward Power Contracts Not designated MWh 2,568.3
 (2,020.9) 547.4
Interest Rate Swaps Designated USD 200,000.0
 —
 200,000.0

At December 31, 2015, DPL had the following outstanding derivative instruments:
Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 10.2
 —
 10.2
Forward Power Contracts Designated MWh 1,676.7
 (7,795.8) (6,119.1)
Forward Power Contracts Not designated MWh 5,049.9
 (1,663.0) 3,386.9

At December 31, 2014, DPL had the following outstanding derivative instruments:
Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 10.5
 —
 10.5
Heating Oil Futures Not designated Gallons 378.0
 —
 378.0
Natural Gas Futures Not designated Dths 200.0
 —
 200.0
Forward Power Contracts Designated MWh 175.0
 (2,991.0) (2,816.0)
Forward Power Contracts Not designated MWh 1,725.2
 (2,707.8) (982.6)

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

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

We alsoIn November 2016, we entered into two interest rate derivative contractsswaps to managehedge the variable interest on our $200.0 million variable interest rate exposure related to anticipated borrowings of fixed-rate debt. Thesetax-exempt First Mortgage Bonds. The interest rate derivative contracts were settledswaps have a combined notional amount of $200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the third quarter of 2013. We do not hedge allincome approach include volatilities, spot and forward benchmark interest rate exposure.rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on interest rate derivative hedgesthe swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.


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The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:
 Years ended December 31, Years ended December 31,
 2015 2014 2013 2016 2015 2014
$ in millions (net of tax) Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
Beginning accumulated derivative gain / (loss) in AOCI $0.2
 $18.3
 $1.4
 $19.2
 $(3.0) $0.5
Beginning accumulated derivative gain in AOCI $9.2
 $17.5
 $0.2
 $18.3
 $1.4
 $19.2
                        
Net gains / (losses) associated with current period hedging transactions 18.2
 —
 (19.0) —
 1.0
 18.7
 15.7
 0.4
 18.2
 —
 (19.0) —
Net gains / (losses) reclassified to earnings:                        
Interest Expense —
 (0.8) —
 (0.9) —
 —
 —
 (0.5) —
 (0.8) —
 (0.9)
Revenues (12.0) —
 18.3
 —
 2.1
 —
 (35.6) —
 (12.0) —
 18.3
 —
Purchased Power 2.8
 —
 (0.5) —
 1.3
 —
 6.4
 —
 2.8
 —
 (0.5) —
Ending accumulated derivative gain in AOCI $9.2
 $17.5
 $0.2
 $18.3
 $1.4
 $19.2
Ending accumulated derivative gain / (loss) in AOCI $(4.3) $17.4
 $9.2
 $17.5
 $0.2
 $18.3
                        
Net gains / (losses) associated with the ineffective portion of the hedging transaction            
Interest Expense $—
 $—
 $—
 $—
 $—
 $0.8
Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.
                        
Portion expected to be reclassified to earnings in the next twelve months (a)
 $5.9
 $(0.8)         $(3.5) $(0.5)        
                        
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 36
 —
         15
 44
        

(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.

Derivatives not designated as hedges
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 consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oilnatural gas futures and certain forward power contracts.

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


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Table of Contents

Regulatory assets and liabilities
In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a 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 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 consolidated statements of results of operations or balance sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the years ended December 31, 2016, 2015 2014 and 2013:2014:
 Year ended December 31, 2015 Year ended December 31, 2016
$ in millions Heating Oil FTRs Power Natural Gas Total Heating Oil FTRs Power Natural Gas Total
Derivatives not designated as hedging instruments
Change in unrealized loss $0.4
 $0.3
 $(6.4) $0.1
 $(5.6)
Change in unrealized gain / (loss) $—
 $0.3
 $4.0
 $—
 $4.3
Realized gain / (loss) (0.3) (0.2) (9.8) (0.1) (10.4) —
 (0.6) (7.2) 2.6
 (5.2)
Total $0.1
 $0.1
 $(16.2) $—
 $(16.0) $—
 $(0.3) $(3.2) $2.6
 $(0.9)
Recorded on Balance Sheet:
Regulatory asset $0.1
 $—
 $—
 $—
 $0.1
 $—
 $—
 $—
 $—
 $—
Recorded in Income Statement: gain / (loss)
Recorded in Statement of Operations: gain / (loss)Recorded in Statement of Operations: gain / (loss)
Revenue —
 —
 (17.3) —
 (17.3)
Purchased Power —
 0.1
 (43.6) —
 (43.5) —
 (0.3) 14.1
 2.6
 16.4
Revenue —
 —
 27.4
 —
 27.4
          
Total $0.1
 $0.1
 $(16.2) $—
 $(16.0) $—
 $(0.3) $(3.2) $2.6
 $(0.9)

 Year ended December 31, 2014 Year ended December 31, 2015
$ in millions Heating Oil FTRs Power Natural Gas Total Heating Oil FTRs Power Natural Gas Total
Derivatives not designated as hedging instruments
Change in unrealized gain $(0.6) $(0.8) $(1.5) $(0.1) $(3.0)
Realized gain (0.1) 0.7
 (3.6) (0.1) (3.1)
Change in unrealized gain / (loss) $0.4
 $0.3
 $(6.4) $0.1
 $(5.6)
Realized gain / (loss) (0.3) (0.2) (9.8) (0.1) (10.4)
Total $(0.7) $(0.1) $(5.1) $(0.2) $(6.1) $0.1
 $0.1
 $(16.2) $—
 $(16.0)
Recorded on Balance Sheet:
Regulatory asset $(0.1) $—
 $—
 $—
 $(0.1) $0.1
 $—
 $—
 $—
 $0.1
Recorded in Income Statement: gain / (loss)
Recorded in Statement of Operations: gain / (loss)Recorded in Statement of Operations: gain / (loss)
Revenue —
 —
 27.4
 —
 27.4
Purchased Power —
 (0.1) (5.1) (0.2) (5.4) —
 0.1
 (43.6) —
 (43.5)
Fuel (0.6) —
 —
 —
 (0.6)
          
Total $(0.7) $(0.1) $(5.1) $(0.2) $(6.1) $0.1
 $0.1
 $(16.2) $—
 $(16.0)

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 Year ended December 31, 2013 Year ended December 31, 2014
$ in millions  Heating Oil FTRs Power Total Heating Oil FTRs Power Natural Gas Total
Derivatives not designated as hedging instruments
Change in unrealized gain / (loss) $—
 $0.3
 $0.6
 $0.9
 $(0.6) $(0.8) $(1.5) $(0.1) $(3.0)
Realized gain / (loss) 0.1
 1.2
 1.1
 2.4
 (0.1) 0.7
 (3.6) (0.1) (3.1)
Total $0.1
 $1.5
 $1.7
 $3.3
 $(0.7) $(0.1) $(5.1) $(0.2) $(6.1)
Recorded in Income Statement: gain / (loss)
Revenue —
 —
 —
 —
Recorded on Balance SheetRecorded on Balance Sheet
Regulatory asset $(0.1) $—
 $—
 $—
 $(0.1)
Recorded in Statement of Operations: gain / (loss)Recorded in Statement of Operations: gain / (loss)
Fuel (0.6) —
 —
 —
 (0.6)
Purchased Power —
 1.5
 1.7
 3.2
 —
 (0.1) (5.1) (0.2) (5.4)
Fuel 0.1
 —
 —
 0.1
O&M —
 —
 —
 —
Total $0.1
 $1.5
 $1.7
 $3.3
 $(0.7) $(0.1) $(5.1) $(0.2) $(6.1)


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The following tables show the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments at December 31, 20152016 and 2014.2015.
Fair Values of Derivative Instruments
December 31, 2016
      Gross Amounts Not Offset in the Consolidated Balance Sheets  
$ in millions Hedging Designation 
Gross Fair Value as presented in the Consolidated Balance Sheets (a)
 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 Designated $11.0
 $(10.5) $—
 $0.5
Forward power contracts Not designated 6.0
 (4.7) —
 1.3
FTRs Not designated 0.1
 —
 —
 0.1
Long-term derivative positions (presented in Other deferred assets)  
  
  
Interest Rate Swaps Designated 1.2
 —
 —
 1.2
Forward power contracts Designated 0.6
 (0.6) —
 —
Forward power contracts Not designated 1.9
 (1.0) —
 0.9
Total assets   $20.8
 $(16.8) $—
 $4.0
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)    
Interest Rate Swaps Designated $0.7
 $—
 $—
 $0.7
Forward power contracts Designated $16.4
 $(10.5) $(5.5) $0.4
Forward power contracts Not designated 7.7
 (4.7) —
 3.0
FTRs Not designated —
 —
 —
 —
Long-term derivative positions (presented in Other deferred liabilities)  
  
Forward power contracts Designated 2.4
 (0.6) (0.8) 1.0
Forward power contracts Not designated 2.0
 (1.0) —
 1.0
Total liabilities   $29.2
 $(16.8) $(6.3) $6.1

(a)Includes credit valuation adjustment.


Fair Values of Derivative Instruments
December 31, 2015
      Gross Amounts Not Offset in the Consolidated Balance Sheets  
$ in millions Hedging Designation 
Gross Fair Value as presented in the Consolidated Balance Sheets (a)
 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 Designated $16.2
 $(7.1) $—
 $9.1
Forward power contracts Not designated 7.3
 (5.5) —
 1.8
FTRs Not designated 0.2
 (0.2) —
 —
Long-term derivative positions (presented in Other deferred assets)  
  
  
Forward power contracts Designated 3.0
 (2.4) —
 0.6
Forward power contracts Not designated 4.0
 (2.7) —
 1.3
Total assets   $30.7
 $(17.9) $—
 $12.8
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)    
Forward power contracts Designated $7.1
 $(7.1) $—
 $—
Forward power contracts Not designated 14.5
 (5.5) (8.0) 1.0
FTRs Not designated 0.5
 (0.2) —
 0.3
Long-term derivative positions (presented in Other deferred liabilities)  
  
Forward power contracts Designated 2.7
 (2.4) —
 0.3
Forward power contracts Not designated 2.7
 (2.7) —
 —
Total liabilities   $27.5
 $(17.9) $(8.0) $1.6

(a)Includes credit valuation adjustment.


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Fair Values of Derivative Instruments
December 31, 2014
      Gross Amounts Not Offset in the Consolidated Balance Sheets  
$ in millions Hedging Designation 
Gross Fair Value as presented in the Consolidated Balance Sheets (a)
 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 Designated $5.6
 $(2.0) $—
 $3.6
Forward power contracts Not designated 5.5
 (3.4) —
 2.1
Long-term derivative positions (presented in Other deferred assets)  
  
  
Forward power contracts Designated 0.3
 (0.3) —
 —
Forward power contracts Not designated 3.5
 (0.9) —
 2.6
Total assets   $14.9
 $(6.6) $—
 $8.3
Liabilities          
Short-term derivative positions (presented in Other current liabilities)    
Forward power contracts Designated $2.1
 $(2.0) $—
 $0.1
Forward power contracts Not designated 7.5
 (3.4) (4.1) —
FTRs Not designated 0.6
 —
 —
 0.6
Heating Oil Futures Not designated 0.4
 —
 (0.4) —
Natural Gas Not designated 0.1
 —
 (0.1) —
Long-term derivative positions (presented in Other deferred liabilities)  
  
Forward power contracts Designated 0.6
 (0.3) (0.3) —
Forward power contracts Not designated 0.9
 (0.9) —
 —
Total liabilities   $12.2
 $(6.6) $(4.9) $0.7

(a)Includes credit valuation adjustment.

As of December 31, 2014, the above table includes Forward power contracts in a short-term asset position of $11.1 million. This table does not include a short-term asset position of $0.1 million of Forward power contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contract.

Credit risk-related contingent features
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. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss.

The aggregate fair value of DPL’s derivative instruments that are in a MTM loss position at December 31, 20152016 is $27.5$29.2 million. This amount is offset by $8.0$6.3 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 $17.9$16.8 million. Since our debt is below investment grade, we could have to post collateral for the remaining $1.6$6.1 million.

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Note 7 – Goodwill and Other Intangible Assets

Goodwill
The following table summarizes the changes in Goodwill by reportable segmentreporting unit for the years ended December 31, 2015 2014 and 2013:2014:
$ in millions DP&L Reporting Unit DPLER Reporting Unit Total DP&L Reporting Unit
Balance at December 31, 2013      
Goodwill $2,440.5
 $135.8
 $2,576.3
Accumulated impairment losses (2,123.5) —
 (2,123.5)
Net balance at December 31, 2013 $317.0
 $135.8
 $452.8
      
Goodwill impairments during 2014 $—
 $(135.8) $(135.8)
Balance at December 31, 2014        
Goodwill $2,440.5
 $135.8
 $2,576.3
 $2,440.5
Accumulated impairment losses (2,123.5) (135.8) (2,259.3) (2,123.5)
Net balance at December 31, 2014 $317.0
 $—
 $317.0
 $317.0
        
Goodwill impairments during 2015 $(317.0) $—
 $(317.0) $(317.0)
Balance at December 31, 2015        
Goodwill $2,440.5
 $135.8
 $2,576.3
 $2,440.5
Accumulated impairment losses (2,440.5) (135.8) (2,576.3) (2,440.5)
Net balance at December 31, 2015 $—
 $—
 $—
 $—

In connection with the acquisition of DPL by AES, DPL allocated the purchase price to goodwill for two reporting units, the DP&L reporting unit, which included DP&L and other entities, and DPLER. Of the total goodwill, approximately $2.4 billion was allocated to the DP&L reporting unit and the remainder was allocated to DPLER. Goodwill represented the value assigned at the Merger date, as adjusted for subsequent changes in the purchase price allocation, less recognized impairments.

DPLER Reporting Unit
During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit. There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter. DPLER was sold on January 1, 2016 and is presented in discontinued operations on the Consolidated StatementStatements of Operations. See Note 16 – Discontinued Operations for additional information.

DP&L Reporting Unit
During the fourth quarter of 2015, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $317.0 million. The reporting unit failed Step 1 as its fair value was less than its carrying amount, which was primarily due to a decrease forecasted in dark spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from the CP product. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were forward commodity price curves, expected revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to have no implied fair value after the hypothetical purchase price allocation under the accounting guidance for business combinations; therefore, a full impairment of the remaining goodwill balance of $317.0 million was recognized. The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no financial statement tax benefit related to the impairment.

During the fourth quarter of 2013, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $306.3 million. In performing the annual goodwill impairment test as of October 1, 2013, Step 1 of the test failed as the fair value of the reporting unit no longer exceeded its carrying amount due primarily to lower estimates of capacity prices in future years as well as lower dark spreads contributing

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to lower overall operating margins for the business. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were capacity price curves, amount of the non-bypassable charge, commodity price curves, dispatching, valuation of regulatory assets and liabilities, discount rates and deferred income taxes. In Step 2, goodwill was determined to have an implied fair value of $317.0 million after the hypothetical purchase price allocation under the accounting guidance for business combinations.

The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no cash or financial statement tax benefit related to the impairment.


Note 8 – Debt
Long-term debt        
$ in millions Interest Rate Maturity December 31, 2015 December 31, 2014 Interest Rate Maturity December 31, 2016 December 31, 2015
First mortgage bonds 1.875% 2016 $445.0
 $445.0
Pollution control series 4.7% 2028 —
 35.3
Pollution control series 4.8% 2034 —
 179.1
Pollution control series 4.8% 2036 100.0
 100.0
Pollution control series - rates from: 0.02% - 0.12% and 0.04% - 0.15% (a) 2040 —
 100.0
Pollution control series - rates from: 1.13% - 1.17% 2020 200.0
 —
Term loan - rates from: 4.00% - 4.01% (a) 2022 $445.0
 $—
First Mortgage Bonds 1.875% 
 —
 445.0
Tax-exempt First Mortgage Bonds 4.8% 2036 100.0
 100.0
Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) 2020 200.0
 200.0
U.S. Government note 4.2% 2061 18.1
 18.2
 4.2% 2061 18.0
 18.1
Capital leases 
 
 0.4
 —
Unamortized deferred financing costs (10.7) (5.0)
Unamortized debt discounts and premiums, net (3.6) (2.8) (5.5) (3.6)
Total long-term debt at subsidiary 759.5
 874.8
 747.2
 754.5
        
Bank term loan - rates from: 2.44% - 2.67% and 2.41% - 2.44% (a) 2020 125.0
 160.0
Bank term loan - rates from: 2.67% - 3.02% (a) and 2.44% - 2.67% (b) 2020 125.0
 125.0
Senior unsecured bonds 6.5% 2016 130.0
 130.0
 6.5% 
 —
 130.0
Senior unsecured bonds 6.75% 2019 200.0
 200.0
 6.75% 2019 200.0
 200.0
Senior unsecured bonds 7.25% 2021 780.0
 780.0
 7.25% 2021 780.0
 780.0
Note to DPL Capital Trust II (b)(c) 8.125% 2031 15.6
 15.6
 8.125% 2031 15.6
 15.6
Unamortized deferred financing costs (8.8) (11.1)
Unamortized debt discounts and premiums, net (0.7) (0.7) (0.6) (0.7)
Subtotal $2,009.4
 $2,159.7
 1,858.4
 1,993.3
Less: current portion (574.9) (20.1) (29.7) (572.8)
Total 1,434.5
 2,139.6
 $1,828.7
 $1,420.5

(a)Range of interest rates for the yearsyear ended December 31, 2015 and 2014, respectively.2016.
(b)Range of interest rates for the year ended December 31, 2015.
(c)Note payable to related party. See Note 13 – Related Party Transactions for additional information.


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At December 31, 2015,2016, maturities of long-term debt are summarized as follows:
 
Due within the years ending December 31, 
Due during the years ending December 31, 
$ in millions  
2016$575.1
201725.1
$29.7
201825.1
29.6
2019225.2
229.6
2020250.2
254.6
2021784.6
Thereafter913.0
555.5
2,013.7
1,883.6
Unamortized discounts and premiums, net(4.3)(6.1)
Total long-term debt$2,009.4
$1,877.5

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

Significant transactions
On July 1, 2015, the $35.3 million of DP&L's 4.7% pollution control bondstax-exempt First Mortgage Bonds due January 2028 and $41.3 million of DP&L's 4.8% pollution control bondstax-exempt First Mortgage Bonds due January of 2034 were called at par and were redeemed with cash.

On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, with a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and maturity date of July 2020. At December 31, 2015,2016, there were two letters

of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 20152016 or 2014.2015. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.

On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bondstax-exempt First Mortgage Bonds due November 2040, terminated the amended standby letter of credit facilities that supported these pollution control bonds,tax-exempt First Mortgage Bonds, and called $137.8 million of 4.8% pollution control bondstax-exempt First Mortgage Bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with a new variable interest rate pollution control bondstax-exempt Term Loan secured by first mortgage bondsFirst Mortgage Bonds in an equivalent amount. In connection with the sale of the new pollution control bonds,tax-exempt First Mortgage Bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L.

On September 19, 2013,November 21, 2016, the DP&L closed a $445.0$200.0 million issuancevariable-rate Term Loan was hedged with floating for fixed rate interest rate swaps, reducing interest rate risk exposure for the term of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. Substantially all property, plant and equipment of DP&L is subject to the lien of the First and Refunding Mortgage. Substantially concurrent with this transaction, DP&L redeemed $470.0 million of previously outstanding first mortgage bonds.

On July 31, 2015, DPL refinanced its revolving credit facility. The new facility has a total size of $205.0 million, a $200.0 million letter of credit sublimit, a feature that provides DPL the ability, under certain circumstances, to increase the size of the facility by an additional $95.0 million and a maturity date of July 2020. DPL's new credit facility also has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by DPLEAES Ohio Generation secured by mortgages on assets of DPLE.AES Ohio Generation. At December 31, 2015,2016, there were two letters of credit in the amount of $3.0$1.7 million outstanding under this facility, with the remaining

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$202.0 $203.3 million of the revolving credit facility remaining available to DPL. Fees associated with this facility were not material during the years ended December 31, 20152016 or 2014.2015.

Prior to refinancing the facility on July 31, 2015, this facility was unsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million and had a five-year term expiring on May 10, 2018; with a springing maturity, meaning that if DPL had not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility would have been July 15, 2016.

Also on July 31, 2015, DPL refinanced its term loan, paying down the outstanding amount of $160.0 million using proceeds from the new term loan of $125.0 million and a combination of cash on hand and draws on short term credit facilities. The new term loan extends the term to July of 2020, pushing back required principal payments to 2017, and providing a mechanism for DPL to request additional term loans to refinance existing indebtedness. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by DPLEAES Ohio Generation secured by mortgages on assets of DPLE.AES Ohio Generation. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019.

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

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. In December 2013, DPL executed an Open Market Repurchase Program and successfully bought back $20.0 million of both the first and second tranche of senior unsecured notes andimmediately retired them.

In October 2014, DPL closed a $200.0 million issuance of senior unsecured bonds. These new bonds were priced at 6.75% and mature on October 1, 2019. Proceeds from the issuance, in addition to a draw on the DPL revolving line of credit and cash on hand, were used to settle a tender offer for $300.0 million of the 6.50% senior unsecured notes maturing October 15, 2016. After this transaction, the DPL Inc. 6.5% Senior Notes due 2016 had an outstanding principleprincipal balance of $130.0 millionmillion.

On January 6, 2016, DPL issued a Notice of Partial Redemption to the Trustee (Wells Fargo Bank N.A.) on the DPL Inc. 6.5% Senior Notes due 2016 (a component of the Dolphin Subsidiary II, Inc. debt). DPL notified the trustee that it was calling $73.0 million of the $130.0 million outstanding principal amount of these notes. The record date of this redemption was January 21, 2016, and the redemption date was February 5, 2016. These bonds were redeemed at par plus accrued interest and a make-whole premium of $2.4 million. On October 17, 2016, the remaining $57.0 million of outstanding principal was redeemed at par on their maturity date with cash on hand.

On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds Due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.

Debt covenants and restrictions
DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement (financing document entered into in connection with the sale of the new $200.0 million of variable rate pollution control bonds,tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L) have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

DPL’s revolving credit agreement and term loan have two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current

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quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant is an EBITDA to Interest Expense ratio that 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.

As of December 31, 2015, DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above.

DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL. DPL’s secured revolving credit agreement, secured term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES, such that DPL cannot make dividend payments unless at the time of, and/or as a result of, the distribution, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions. As of December 31, 2015,2016, DPL’s leverage ratio was at 1.031.45 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015,2016, DPL was prohibited under each of these agreements from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the new $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that after separation required compliance with this financial covenant shall be suspended (a) any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility or (b) for the time period January 1, 2017 to December 31, 2017 (as modified by the amendment described below) if during such time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment DP&L’s Total Debt to Total Capitalization ratio for the period ending December 31, 2016 is 0.53 to 1.00, compared to 0.68 to 1.00 before the amendment. The amendment also changed, for each amendment, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

As of December 31, 2016, DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above.

Note 9 – Income Taxes

DPL’s components of income tax expense on continuing operations were as follows:
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Computation of tax expense      
Computation of tax expense / (benefit)      
Federal income tax expense / (benefit)(a)
 $(81.0) $25.4
 $(71.7) $(277.6) $(81.0) $25.4
Increases (decreases) in tax resulting from:            
State income taxes, net of federal effect (0.1) 0.8
 1.1
 (1.0) (0.1) 0.8
Depreciation of AFUDC - Equity (3.5) (3.4) (3.2) 2.7
 (3.5) (3.4)
Investment tax credit amortized (0.5) (0.5) (0.5) (0.4) (0.5) (0.5)
Section 199 - domestic production deduction (4.1) (1.1) (4.1) (4.5) (4.1) (1.1)
Non-deductible goodwill impairment 111.0
 —
 107.2
 —
 111.0
 —
Accrual (settlement) for open tax years —
 (6.6) (8.8) 2.2
 —
 (6.6)
Other, net (b)
 (1.8) 0.8
 (0.2) (0.2) (1.8) 0.8
Total tax expense $20.0
 $15.4
 $19.8
Tax expense / (benefit) $(278.8) $20.0
 $15.4
            
Components of tax expense      
Components of tax expense / (benefit)      
Federal - current $30.1
 $(5.2) $(2.5) $14.7
 $30.1
 $(5.2)
State and Local - current 0.8
 0.4
 —
 0.6
 0.8
 0.4
Total current 30.9
 (4.8) (2.5) 15.3
 30.9
 (4.8)
      
Federal - deferred (9.9) 19.6
 20.6
 (290.2) (9.9) 19.6
State and local - deferred (1.0) 0.6
 1.7
 (3.9) (1.0) 0.6
Total deferred (10.9) 20.2
 22.3
 (294.1) (10.9) 20.2
Total tax expense $20.0
 $15.4
 $19.8
Tax expense / (benefit) $(278.8) $20.0
 $15.4

(a)The statutory tax rate of 35% was applied to pre-tax earnings.
(b)Includes expense of $(0.3) million, $0.2 million and $0.4 million in the years ended December 31, 2016, 2015, and 2014, respectively, of income tax related to adjustments from prior years.

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Effective and Statutory Rate Reconciliation
The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DPL's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 20152016, 20142015 and 20132014:
 Years ended December 31, Years ended December 31,
 2015 2014 2013 2016 2015 2014
Statutory Federal tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %
State taxes, net of Federal tax benefit 0.1 % 1.1 % (0.6)% 0.1 % 0.1 % 1.1 %
AFUDC - Equity 1.5 % (4.7)% 1.5 % (0.3)% 1.5 % (4.7)%
Amortization of investment tax credits 0.2 % (0.7)% 0.2 % — % 0.2 % (0.7)%
Section 199 - domestic production deduction 1.8 % (1.6)% 2.0 % 0.6 % 1.8 % (1.6)%
Non-deductible goodwill impairment (48.0)% — % (52.1)% — % (48.0)% — %
Other, net 0.8 % (7.9)% 4.3 % (0.3)% 0.8 % (7.9)%
Effective tax rate (8.6)% 21.2 % (9.7)% 35.1 % (8.6)% 21.2 %

Deferred Income Taxes
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
Components of Deferred Tax Assets and Liabilities
 December 31, December 31,
$ in millions 2015 2014 2016 2015
Net non-current Assets / (Liabilities)    
Net non-current assets / (liabilities)    
Depreciation / property basis $(539.8) $(548.2) $(255.3) $(539.8)
Income taxes recoverable (12.0) (14.8) (11.9) (12.0)
Regulatory assets (10.6) (18.0) (7.8) (10.6)
Investment tax credit 0.7
 1.5
 0.5
 0.7
Compensation and employee benefits 3.1
 3.2
 5.5
 3.1
Intangibles (8.4) (7.0) (1.5) (8.4)
Long-term debt (1.1) (1.5) (0.7) (1.1)
Other (c)(a)
 (0.6) (2.5) 18.8
 (0.6)
Net non-current liabilities $(568.7) $(587.3) $(252.4) $(568.7)
    
Net current Assets / (Liabilities) (d)
    
Other $—
 $1.1
Net current assets / (liabilities) $—
 $1.1

(a)The statutory tax rate of 35% was applied to pre-tax earnings.
(b)Includes expense of $0.2 million, $0.4 million and $0.0 million in the years ended December 31, 2015, 2014, and 2013, respectively, of income tax related to adjustments from prior years.
(c)The Other non-current liabilities caption includes deferred tax assets of $24.9 million in 2016 and $26.0 million in 2015 and $27.1 million in 2014 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $3.3 million in 2016 and $17.2 million in 2015 and $18.9 million in 2014.2015. These net operating loss carryforwards expire from 20162017 to 2030.
(d)
Amounts are included within Other prepayments and current assets and Other current liabilities on the Consolidated Balance Sheet of DPL at December 31, 2014.


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The following table presents the tax expense / (benefit) related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Tax expense / (benefit) $6.3
 $(9.1) $15.4
 $(9.6) $6.3
 $(9.1)


Uncertain Tax Positions
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
  
$ in millions  
Balance at December 31, 2013$8.8
Calendar 2014 
Tax positions taken during prior period2.8
Lapse of Statute of Limitations(8.6)
Balance at December 31, 20143.0
$3.0
Calendar 2015  
Tax positions taken during prior period—
—
Lapse of Statute of Limitations—
—
Balance at December 31, 2015$3.0
3.0
Calendar 2016 
Tax positions taken during prior period2.2
Lapse of Statute of Limitations(1.5)
Balance at December 31, 2016$3.7

Of the December 31, 20152016 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.

We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued as well as the expense / (benefit) recorded were not material for the years ended December 31, 2016, 2015 2014 and 2013.2014.

Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal – 20102011 and forward
State and Local – 20102011 and forward

None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations.

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 in 2013.

Note 10 – Benefit Plans

Defined contribution plans
DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.

Certain non-union and union employees become eligible to participate in the managementtheir respective plan on the first day of the month following the first full calendar month of employment; provided the employee worked at least 160 hours in that calendar month. Union employees become eligible to participate in the union plan on the first day of the first month following 30 days of employment. Effective January 1, 2016, employees in both plans are eligible to participate upon date of hire.


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Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,100$2,200 for 20152016 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions.

For the years ended December 31, 2016, 2015 2014 and 2013,2014, DP&L's contributions to all defined contribution plans were $4.9 million, $4.8 million $4.7 million and $4.8$4.7 million per year, respectively.

Defined benefit plans
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including accounting, legal,

human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.

Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.

In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners in our co-owned generating plants related to our share of their pension costs within Pension, retiree and other benefits on our Consolidated Balance Sheets.

We recognize an asset for a plan’s overfunded status and 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. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.

Postretirement benefits
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $15.8 million and $15.0 million at December 31, 2016 and 2015, respectively, were not material to the consolidated financial statements in the periods covered by this report.


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The following tables set forth the changes in our pension and postemployment benefit plans’plan's obligations and assets recorded on the balance sheets at December 31, 20152016 and 2014.2015. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presentedaggregate and have not been adjusted for postemployment obligations include both health$1.3 million and life insurance benefits.$2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015.
$ in millions Pension
  Years ended December 31,
  2015 2014
Change in benefit obligation    
Benefit obligation at January 1 $443.8
 $370.5
Service cost 7.1
 5.9
Interest cost 17.3
 17.5
Plan amendments —
 6.8
Actuarial (gain) / loss (34.5) 67.3
Benefits paid (22.9) (24.2)
Benefit obligation at December 31 410.8
 443.8
Change in plan assets    
Fair value of plan assets at January 1 371.7
 349.1
Actual return on plan assets (8.8) 46.4
Contributions to plan assets 5.4
 0.4
Benefits paid (22.9) (24.2)
Fair value of plan assets at December 31 345.4
 371.7
     
Funded status of plan $(65.4) $(72.1)
     
  December 31,
Amounts recognized in the Balance sheets 2015 2014
Current liabilities $(0.4) $(0.4)
Non-current liabilities (65.0) (71.7)
Net liability at December 31, $(65.4) $(72.1)
     
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax    
Components:    
Prior service cost $12.0
 $14.1
Net actuarial loss 94.7
 103.4
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $106.7
 $117.5
Recorded as:    
Regulatory asset $91.1
 $99.0
Regulatory liability —
 —
Accumulated other comprehensive income 15.6
 18.5
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $106.7
 $117.5


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$ in millions Postretirement Pension
 Years ended December 31, Years ended December 31,
 2015 2014 2016 2015
Change in benefit obligation        
Benefit obligation at beginning of period $19.6
 $19.7
Benefit obligation at January 1 $410.8
 $443.8
Service cost 0.2
 0.2
 5.7
 7.1
Interest cost 0.6
 0.8
 14.7
 17.3
Plan curtailment 2.5
 —
Actuarial (gain) / loss (1.1) 0.2
 9.0
 (34.5)
Benefits paid (1.5) (1.3) (23.1) (22.9)
Benefit obligation at end of period 17.8
 19.6
Benefit obligation at December 31 419.6
 410.8
    
Change in plan assets        
Fair value of plan assets at beginning of period 3.3
 3.7
Contributions to plan assets 1.0
 0.9
Fair value of plan assets at January 1 345.4
 371.7
Actual return on plan assets 13.3
 (8.8)
Employer contributions 5.4
 5.4
Benefits paid (1.5) (1.3) (23.1) (22.9)
Fair value of plan assets at end of period 2.8
 3.3
Fair value of plan assets at December 31 341.0
 345.4
        
Funded status of plan $(15.0) $(16.3)
    
Unfunded status of plan $(78.6) $(65.4)
 December 31,    
 2015 2014 December 31,
Amounts recognized in the Balance sheets     2016 2015
Current liabilities $(0.4) $(0.5) $(0.4) $(0.4)
Non-current liabilities (14.6) (15.8) (78.2) (65.0)
Net liability at December 31, $(15.0) $(16.3) $(78.6) $(65.4)
    
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax        
Components:        
Prior service cost $0.3
 $0.4
 $8.8
 $12.0
Net actuarial gain (5.5) (5.0)
Net actuarial loss 108.9
 94.7
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $(5.2) $(4.6) $117.7
 $106.7
Recorded as:        
Regulatory asset $0.3
 $0.4
 $97.1
 $91.1
Regulatory liability (5.1) (4.8)
Accumulated other comprehensive income (0.4) (0.2) 20.6
 15.6
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $(5.2) $(4.6) $117.7
 $106.7

The accumulated benefit obligation for our defined benefit pension plans was $401.2$409.2 million and $431.0$401.2 million at December 31, 20152016 and 2014,2015, respectively.


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The net periodic benefit cost of the pension and postretirement plans were:
Net Periodic Benefit Cost - Pension  
  Years ended December 31,
$ in millions 2015 2014 2013
Service cost $7.1
 $5.9
 $7.2
Interest cost 17.3
 17.5
 15.6
Expected return on assets (a)
 (22.6) (22.9) (23.3)
Amortization of unrecognized:      
Actuarial gain 5.8
 3.4
 4.9
Prior service cost 2.0
 1.5
 1.5
Net periodic benefit cost $9.6
 $5.4
 $5.9

Net Periodic Benefit Cost - Postretirement  
Net Periodic Benefit Cost  
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Service cost $0.2
 $0.2
 $0.2
 $5.7
 $7.1
 $5.9
Interest cost 0.6
 0.8
 0.8
 14.7
 17.3
 17.5
Expected return on assets (a)
 (0.1) (0.2) (0.1) (22.8) (22.6) (22.9)
Plan curtailment 3.8
 —
 —
Amortization of unrecognized:          
  
Actuarial loss (0.6) (0.6) (0.5) 4.3
 5.8
 3.4
Prior service cost 0.1
 —
 —
 1.8
 2.0
 1.5
Net periodic benefit cost $0.2
 $0.2
 $0.4
 $7.5
 $9.6
 $5.4
      
Rates relevant to each year's expense calculations      
Discount rate 4.49% 4.02% 4.86%
Expected return on plan assets 6.50% 6.50% 6.75%

Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Pension  
  Years ended December 31,
$ in millions 2015 2014 2013
Net actuarial loss / (gain) $(3.0) $43.8
 $(12.0)
Prior service cost —
 6.8
 —
Reversal of amortization item:      
Net actuarial loss (5.8) (3.4) (4.9)
Prior service cost (2.0) (1.5) (1.5)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(10.8) $45.7
 $(18.4)
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(1.2) $51.1
 $(12.5)


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Postretirement  
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Net actuarial loss / (gain) $(1.1) $0.4
 $(2.0) $20.9
 $(3.0) $43.8
Prior service cost —
 —
 6.8
Plan curtailment (3.8) —
 —
Reversal of amortization item:            
Net actuarial gain 0.6
 0.6
 0.5
Net actuarial loss (4.3) (5.8) (3.4)
Prior service cost $(0.1) $—
 $—
 (1.8) (2.0) (1.5)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(0.6) $1.0
 $(1.5) $11.0
 $(10.8) $45.7
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(0.4) $1.2
 $(1.1) $18.5
 $(1.2) $51.1

Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 20162017 are:
$ in millions Pension Postretirement Pension
Actuarial gain / (loss) $4.3
 $(0.6)
Actuarial loss $5.8
Prior service cost $1.9
 $0.1
 $1.4

Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.

At December 31, 2015,2016, we are maintaining our long termlong-term rate of return assumption of 6.50% for pension plan assets. In addition, we are decreasing our long-termThe rate of return assumption to 3.90% from 4.50% for other postemployment benefit plan assets. These rates of return representrepresents our long-term assumptions based on our long-term portfolio mixes.mix. Also, at December 31, 2015,2016, we have increaseddecreased our assumed discount rate to 4.49%4.28% from 4.02%4.49% for pension and to 4.10% from 3.71% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in 2017 pension expense of approximately $3.5 million. A one percent decrease in the rate of return assumption for pension would result in an increase in 2017 pension expense of approximately $3.5 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.2

$0.3 million to 20162017 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3$0.4 million to 20162017 pension expense. A one percent change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.

In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2015.2016. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Effective January 1, 2016, we will applyapplied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies for more information.

In future periods, differences in the actual return on pension and other post-employment benefit plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any, to the plans.


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The weighted average assumptions used to determine benefit obligations at December 31, 2016, 2015 2014 and 20132014 were:
Benefit Obligation Assumptions Pension Postretirement
  2015 2014 2013 2015 2014 2013
Discount rate for obligations 4.49% 4.02% 4.86% 4.10% 3.71% 4.58%
Rate of compensation increases 3.94% 3.94% 3.94% N/A N/A N/A

The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013 were:
Net Periodic Benefit
Cost / (Income) Assumptions
 Pension Postretirement
  2015 2014 2013 2015 2014 2013
Discount rate 4.02% 4.86% 4.04% 3.81% 4.51% 4.58%
Expected rate of return on plan assets 6.50% 6.75% 6.75% 4.50% 6.00% 6.00%
Rate of compensation increases 3.94% 3.94% 3.94% N/A N/A N/A

The assumed health care cost trend rates at December 31, 2015, 2014 and 2013 are as follows:
Health Care Cost Assumptions Expense Benefit Obligation
  2015 2014 2013 2015 2014 2013
Pre - age 65            
Current health care cost trend rate 6.97% 7.75% 8.00% 6.85% 6.97% 7.75%
             
Year trend reaches ultimate 2029 2023 2019 2036 2029 2023
Post - age 65            
Current health care cost trend rate 6.97% 6.75% 7.50% 6.85% 6.97% 6.75%
             
Year trend reaches ultimate 2029 2021 2018 2036 2029 2021
             
Ultimate health care cost trend rate 4.50% 5.00% 5.00% 4.50% 4.50% 5.00%

The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postemployment benefit cost and the accumulated postemployment benefit obligation:
Effect of change in health care cost trend rate
$ in millions 
One-percent
increase
 
One-percent
decrease
Service cost plus interest cost $0.1
 $—
Benefit obligation $0.8
 $(0.7)
Benefit Obligation Assumptions Pension
  2016 2015 2014
Discount rate for obligations 4.28% 4.49% 4.02%
Rate of compensation increases 3.94% 3.94% 3.94%

Pension plan assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.


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Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the Plan’splan’s long-term objectives. The long-term target allocations for plan assets are 18%28% – 38%48% for equity securities and 58%42% – 86%70% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds.

Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small target allocation of 6% to a core property fund, as well as a small allocation to a hedge fund.

Most of our Planplan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core property collective fund and the Common collective fund areis measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.


The following table summarizes our target pension plan allocation for 2015:2016:
 Percentage of plan assets as of December 31, 
Long-Term
Mid-Point
Target
Allocation
 Percentage of plan assets as of December 31,
Asset category 
Long-Term
Mid-Point
Target
Allocation
 2015 2014 2016 2015
Equity Securities 28% 17% 18% 38% 37% 17%
Debt Securities 72% 67% 69% 56% 53% 67%
Real Estate —% 9% 7%��6% 10% 9%
Other —% 7% 6% —% —% 7%


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The fair values of our pension plan assets at December 31, 20152016 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2015
Asset Category
$ in millions
 Market Value at December 31, 2015 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Equity securities (a)
        
Small/Mid cap equity $9.2
 $9.2
 $—
 $—
Large cap equity 20.2
 20.2
 —
 —
International equity 18.2
 18.2
 —
 —
Emerging markets equity 2.7
 2.7
 —
 —
SIIT dynamic equity 10.0
 10.0
 —
 —
Total equity securities 60.3
 60.3
 —
 —
         
Debt securities (b)
        
Emerging markets debt 6.3
 6.3
 —
 —
High yield bond 6.3
 6.3
 —
 —
Long duration fund 219.5
 219.5
 —
 —
Total debt securities 232.1
 232.1
 —
 —
         
Other investments (c)
        
Core property collective fund 30.2
 —
 30.2
 —
Common collective fund 22.8
 —
 22.8
 —
Total other investments 53.0
 —
 53.0
 —
Total pension plan assets $345.4
 $292.4
 $53.0
 $—
Fair Value Measurements for Pension Plan Assets at December 31, 2016
Asset Category
$ in millions
 Market Value at December 31, 2016 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Mutual funds:        
U.S. equities (a)
 $81.4
 $81.4
 $—
 $—
International equities (a)
 44.4
 44.4
 —
 —
Fixed income (b)
 151.1
 151.1
 —
 —
Fixed income securities:        
U.S. Treasury securities 31.0
 31.0
 —
 —
Other investments:        
Core property collective fund (c)
 33.1
 —
 33.1
 —
Total pension plan assets $341.0
 $307.9
 $33.1
 $—

(a)This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies.estate. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.



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The fair values of our pension plan assets at December 31, 20142015 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2014
Asset Category
$ in millions
 Market Value at December 31, 2014 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Equity securities (a)
        
Small/Mid cap equity $10.6
 $10.6
 $—
 $—
Large cap equity 22.2
 22.2
 —
 —
International equity 18.2
 18.2
 —
 —
Emerging markets equity 2.8
 2.8
 —
 —
SIIT dynamic equity 11.6
 11.6
 —
 —
Total equity securities 65.4
 65.4
 —
 —
         
Debt securities (b)
        
Emerging markets debt 6.0
 6.0
 —
 —
High yield bond 6.5
 6.5
 —
 —
Long duration fund 242.7
 242.7
 —
 —
Total debt securities 255.2
 255.2
 —
 —
         
Cash and cash equivalents (c)
        
Cash 1.6
 1.6
 —
 —
         
Other investments (d)
        
Core property collective fund 26.3
 —
 26.3
 —
Common collective fund 23.2
 —
 23.2
 —
Total other investments 49.5
 —
 49.5
 —
Total pension plan assets $371.7
 $322.2
 $49.5
 $—
Fair Value Measurements for Pension Plan Assets at December 31, 2015
Asset Category
$ in millions
 Market Value at December 31, 2015 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Mutual funds:        
U.S. equities (a)
 $39.4
 $39.4
 $—
 $—
International equities (a)
 20.9
 20.9
 —
 —
Fixed income (b)
 232.1
 232.1
 —
 —
Other investments: (c)
        
Core property collective fund 30.2
 —
 30.2
 —
Common collective fund 22.8
 —
 22.8
 —
Total pension plan assets $345.4
 $292.4
 $53.0
 $—

(a)This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c)This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value.
(d)This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

The fair values of our other postemployment benefit plan assets at December 31, 2015 by asset category are as follows:
Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2015
Asset Category
$ in millions
 Market Value at December 31, 2015 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
JP Morgan Core Bond Fund (a)
 $2.8
 $2.8
 $—
 $—

(a)This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

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The fair values of our other postemployment benefit plan assets at December 31, 2014 by asset category are as follows:
Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2014
Asset Category
$ in millions
 Market Value at December 31, 2014 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
JP Morgan Core Bond Fund (a)
 $3.3
 $3.3
 $—
 $—

(a)This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

Pension funding
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. We contributed $5.0 million, $0.0$5.0 million, and $0.0 million to the pension plan during the years ended December 31, 2016, 2015 2014 and 2013,2014, respectively.

We expect to make contributions of $0.4 million to our SERP in 2016 to cover benefit payments. We also expect to contribute $1.1 million to our other postemployment benefit plans in 20162017 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January 2016.2017.

TheFunding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, (the Act) contained new requirements for our single employer defined benefit pension plan. In additionas well as targeted funding levels necessary to establishing a 100%meet certain thresholds.

From an ERISA funding perspective, DP&L’s funded target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2015 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Actliability percentage was 112.54% and is estimated to be 112.54% until100%. In addition, DP&L must also contribute the 2016 status is certified in September 2016 fornormal service cost earned by active participants during the 2016 plan year. The Worker, Retiree, and Employer Recovery Actfunding of 2008 (WRERA),normal cost is expected to be approximately $5.7 million in 2017, which was signed into law on December 23, 2008, grantsincludes $0.6 million for plan sponsors certain relief from funding requirements and benefit restrictionsexpenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the Act.remaining annual installments, the excess is separately amortized over a seven-year period. DP&L’s funding policy for the pension plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes.

Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated future benefit payments and Medicare Part D reimbursements
Estimated future benefit payments  
$ in millions due within the following years: Pension Postretirement Pension
2016 $24.6
 $1.7
2017 $25.2
 $1.6
 $25.0
2018 $25.8
 $1.5
 $25.5
2019 $26.3
 $1.4
 $26.0
2020 $26.7
 $1.4
 $26.4
2021 - 2025 $134.8
 $5.7
2021 $26.7
2022 - 2026 $139.6


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Note 11 – Equity

Redeemable Preferred Stock of Subsidiary
DP&L hashad 228,508 shares of $100 par value preferred stock 4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015 and 2014. DP&L also has $25 par valueprior to the preferred stock 4,000,000 shares authorized, none of which was outstanding at December 31, 2015 or 2014.redemption on October 13, 2016 (see below). The table below details the preferred shares outstanding at December 31, 2016 and 2015:
   December 31, 2015 and 2014 
Carrying Value (a)
($ in millions)
       
Carrying Value (b)
($ in millions)
 
Preferred
Stock
Rate
 
Redemption price
($ per share)
 
Shares
Outstanding
 December 31, 2015 December 31, 2014 
Preferred
Stock
Rate
 
Redemption price
($ per share)
 
Shares
Outstanding (a)
 December 31, 2016 December 31, 2015
DP&L Series A
 3.75% $102.50
 93,280
 $7.4
 $7.4
 3.75% $102.50
 93,280
 $—
 $7.4
DP&L Series B
 3.75% $103.00
 69,398
 5.6
 5.6
 3.75% $103.00
 69,398
 —
 5.6
DP&L Series C
 3.90% $101.00
 65,830
 5.4
 5.4
 3.90% $101.00
 65,830
 —
 5.4
Total     228,508
 $18.4
 $18.4
     228,508
 $—
 $18.4

(a)
DP&L's preferred stock was redeemed in October 2016. See below for more information.
(b)Carrying value is fair value at the Merger date plus cumulative accrued dividends, of which there were none at December 31, 20152016 and 2014.2015.

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends, of which there were none at December 31, 2015. In addition,
DP&L’s Amended Articles of Incorporation contain provisions that permitpermitted preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event iswas not solely within the control of DP&L, the preferred stock iswas presented on the Consolidated Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.

On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital.

Dividend Restrictions
DPL’s Amended Articles of Incorporation (the Articles) contain provisions which state that DPL may not make a distribution to its shareholder or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no Event of Default (as defined in the Articles) and no such Event of Default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, (b)(ii) if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder and the making of loans to its affiliates (other than subsidiaries) cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions.

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not affected DP&L’s ability to pay cash dividends and, at December 31, 2015, DP&L’s retained earnings of $437.3 million were all available for common stock dividends payable to DPL.We do not expect this restriction to have an effect on the payment of cash dividends in the future. DPL records dividends on preferred stock of DP&L within Interest expense on the Statements of Operations.

Common Stock
Effective on the Merger date, DPL adopted Amended Articles of Incorporation providingprovided for 1,500 authorized common shares, of which one share is outstanding at December 31, 2015.2016.

As described above, DPL’s Amended Articles of Incorporation contain restrictions on DPL’s ability to make dividends, distributions and affiliate loans (other than to its subsidiaries), including restrictions of making such dividends, distributions and loans if certain financial ratios exceed specified levels and DPL’s senior long-term debt rating from a rating agency is below investment grade. As of December 31, 2015,2016, DPL’s leverage ratio was at 1.03

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1.45 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015,2016, DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2015.2016. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. After the fixed-asset impairments recorded during the second and fourth quarters of 2016 and as of December 31, 2016, DP&L's equity ratio was 32% and its retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L.

Note 12 – Contractual Obligations, Commercial Commitments and Contingencies

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

At December 31, 2015,2016, DPL had $17.3$16.6 million of guarantees on behalf of DPLEAES Ohio Generation to third parties for future financial or performance assurance under such agreements. In addition, DPL had $1.9 million of guarantees on behalf of DPLER which were released in January 2016 as a result of the sale of DPLER. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE and present obligations of DPLERAES Ohio Generation to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. All guarantees on behalf of DPLER were terminated in January 2016. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.5$2.3 million and $1.6$0.5 million at December 31, 20152016 and 2014,2015, respectively.

To date, DPL has not incurred any losses related to these guarantees 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 has a 4.9% equity ownership interest in an electric generation companyOVEC which is recorded using the cost method of accounting under GAAP. At December 31, 2015,2016, DP&L could be responsible for the repayment of 4.9%, or $74.5$74.2 million, of a $1,519.9$1,514.3 million debt obligation comprised of both fixed and variable rate securities with maturities between 20162017 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015,2016, we have no knowledge of such a default.

Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2015,2016, these include:
 Payments due in: Payments due in:
$ in millions Total 
Less than
1 year
 
2 - 3
years
 
4 - 5
years
 
More than
5 years
 Total 
Less than
1 year
 
2 - 3
years
 
4 - 5
years
 
More than
5 years
DPL:                    
Coal contracts (a)
 374.2
 186.9
 187.3
 —
 —
Coal and limestone contracts (a)
 $284.3
 $230.3
 $54.0
 $—
 $—
Purchase orders and other contractual obligations 83.8
 24.4
 30.0
 29.4
 —
 $109.8
 $43.1
 $33.6
 $33.1
 $—

(a)
Total at DP&L operated units.

Coal contracts:
DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2015, 73%2016, 92% of our future committed coal obligations are with a single supplier.two suppliers. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.


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Purchase orders and other contractual obligations:
At December 31, 2015,2016, DPL had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates.

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 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, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2015,2016, cannot be reasonably determined.

Environmental Matters
DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include:
The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions,
Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or

pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,
•
Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO2, particulates, mercury, acid gases, NOX, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,
Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs,
Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.

In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies of approximately $0.9 million for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.

Note 13 – Related Party Transactions

Service Company
In December 2013, an agreement was signed, effectiveEffective January 1, 2014, whereby the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in

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fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.

Benefit plans
DPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.

Long-term Compensation Plan
During 2016, 2015 and 2014, many of DPL’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units and options to purchase shares of AES common stock, however no stock options were granted in 2016. All such components vest over a three-year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years are not subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2016, 2015 and 2014 was $0.5 million, $0.5 million and $0.0 million, respectively, and was included in “Other Operating Expenses” on DPL’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on DPL’s Consolidated Balance Sheets in accordance with FASC 718 “Compensation - Stock Compensation.”


The following table provides a summary of these transactions:
 For the years ended December 31, For the years ended December 31,
$ in millions 2015 2014 2016 2015 2014
Transactions with the Service Company          
Charges for services provided $36.0
 $35.8
 $42.8
 $36.0
 $35.8
Charges to the Service Company $6.2
 $2.4
 $4.6
 $6.2
 $2.4
Transactions with other AES affiliates:      
Payments for health, welfare and benefit plans $9.6
 $15.5
 $17.8
          
Transactions with the Service Company: At December 31, 2015 At December 31, 2014
Balances with related parties: At December 31, 2016 At December 31, 2015  
Net payable to the Service Company $(0.5) $(4.7) $(2.0) $(0.5)  
Net prepayment with / (payable) to other AES affiliates $(2.5) $0.1
  

DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 20152016 and 2014,2015, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 20152016 and 2014,2015, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 – Debt for additional information.

In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.

Income taxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. Under this agreement, DPL had a net payablereceivable balance under this agreement of $97.2 million and $50.5 million and $16.1 million as ofat December 31, 20152016 and 2014,2015, respectively, which is recorded in Accrued taxesOther current assets on the accompanying Consolidated Balance Sheets.

Note 14 – Business Segments

DPLDuring the fourth quarter of 2016, DPL's had twomanagement reassessed our reportable business segments consistingin connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of the operations of two of its wholly-owned subsidiaries, DP&L&L’s (Utility segment)and DPLER (Competitive Retail segment which included DPLER's wholly-owned subsidiary, MC Squared). This is how we viewed our business and made decisions on howgeneration assets to allocate resources and evaluate performance.

The Competitive Retail segment, DPLER’s competitive retail electric service business, was sold on January 1, 2016 (see Note 16 – Discontinued Operations).AES Ohio Generation. DPL now operatescurrently manages the business through onetwo reportable operating segments, the Transmission and Distribution ("T&D") segment and the UtilityGeneration segment. Segment disclosures for 2014The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that income / (loss) from continuing operations before income tax best reflects the underlying business performance of DPL and 2013 have not been restated to showis the competitive retail segment as a discontinued operation and therefore do not tie tomost relevant measure considered in DPL’s internal evaluation of the Statementsfinancial performance of Operations.its segments. The segments are discussed further below:

Transmission and Distribution Segment
The UtilityT&D segment is comprised primarily of DP&L’s electric generation, transmission and distribution businesses, which generate and deliverdistribute electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired electric generating stations and distributes electricity to approximately 517,000more than 519,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L&L’s also sold electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’selectric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law.


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The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased fromregulators. Accordingly, DP&L. Intercompany sales 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. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation

separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.

Generation Segment
The Generation segment is comprised of AES Ohio Generation and DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates peaking generating facilities, and DP&L owns multiple coal-fired and peaking electric generating facilities. Both AES Ohio Generation and DP&L primarily sell their generated energy and capacity into the PJM wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process. Prior to DPLER were based on fixed-price contracts for each customer; the price approximated market prices for wholesale power at the inception of each customer’s contract. These agreements were terminated in connection with theJanuary 1, 2016 sale of DPLER, on January 1, 2016.DP&L also had full requirements sales to DPLER.

Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s debt. Management evaluates segment performance based on gross margin.debt and adjustments related to purchase accounting from the Merger. 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. Certain shared and corporate costs are allocated among reporting segments.


The following tables present financial information for each of DPL’s reportable business segments:
$ in millions Utility Other Adjustments and Eliminations DPL Consolidated
Year ended December 31, 2015
Revenues from external customers $1,550.8
 $62.0
 $—
 $1,612.8
Intersegment revenues 1.5
 4.2
 (5.7) —
Total revenues 1,552.3

66.2
 (5.7) 1,612.8
         
Fuel 244.7
 15.1
 —
 259.8
Purchased power 555.7
 8.9
 (2.0) 562.6
Gross margin (a)
 $751.9

$42.2
 $(3.7) $790.4
         
Depreciation and amortization $138.2
 $(3.6) $—
 $134.6
Goodwill impairment (Note 7) $—
 $317.0
 $—
 $317.0
Fixed asset impairment $—
 $—
 $—
 $—
Interest expense $30.9
 $87.6
 $(0.2) $118.3
Income tax expense / (benefit) $35.1
 $(15.1) $—
 $20.0
Net income / (loss) from continuing operations $106.4
 $(357.8) $—
 $(251.4)
Discontinued operations, net of tax $—
 $12.4
 $—
 $12.4
Net income / (loss) $106.4
 $(345.4) $—
 $(239.0)
         
Cash capital expenditures $127.0
 $10.2
 $—
 $137.2
         
Total assets (end of year) (b)
 $3,365.8
 $1,314.4
 $(1,339.4) $3,340.8
$ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated
Year ended December 31, 2016
Revenues from external customers $806.7
 $611.5
 $9.1
 $—
 $1,427.3
Intersegment revenues 1.3
 —
 5.7
 (7.0) —
Total revenues $808.0

$611.5
 $14.8
 $(7.0) $1,427.3
           
Depreciation and amortization $71.0
 $55.4
 $5.9
 $—
 $132.3
Fixed-asset impairment (Note 15) $—
 $1,353.5
 $(494.5) $—
 $859.0
Interest expense $24.7
 $0.4
 $81.3
 $(0.3) $106.1
Income / (loss) from continuing operations before income tax $143.0
 $(1,353.9) $417.6
 $—
 $(793.3)
           
Cash capital expenditures $83.4
 $64.2
 $0.9
 $—
 $148.5
           
Total assets (end of year) $1,710.5
 $472.3
 $673.6
 $(437.2) $2,419.2

$ in millions T&D Generation Other Adjustments and Eliminations 
DPL Consolidated
Year ended December 31, 2015
Revenues from external customers (b)
 $855.5
 $770.3
 $6.7
 $(19.7) $1,612.8
Intersegment revenues 1.5
 186.6
 4.2
 (192.3) —
Total revenues $857.0
 $956.9
 $10.9
 $(212.0) $1,612.8
           
Depreciation and amortization $71.5
 $72.6
 $(9.5) $—
 $134.6
Goodwill impairment (Note 7) $—
 $—
 $317.0
 $—
 $317.0
Interest expense $28.9
 $2.9
 $86.8
 $(0.3) $118.3
Income / (loss) from continuing operations before income tax $188.1
 $(28.7) $(390.8) $—
 $(231.4)
           
Cash capital expenditures $98.3
 $35.2
 $3.7
 $—
 $137.2
           
Total assets (end of year) (a)
 $1,688.8
 $1,805.0
 $1,170.3
 $(1,339.4) $3,324.7

(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.
(b)Includes assets held for sale related to the sale of DPLER.
(b)Wholesale revenue for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax.

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$ in millions Utility Competitive Retail Other Adjustments and Eliminations DPL Consolidated
Year ended December 31, 2014
Revenues from external customers $1,181.2
 $533.6
 $48.2
 $—
 $1,763.0
Intersegment revenues 487.1
 —
 5.5
 (492.6) —
Total revenues 1,668.3
 533.6
 53.7
 (492.6) 1,763.0
           
Fuel 314.9
 —
 (10.4) —
 304.5
Purchased power 582.4
 491.8
 7.5
 (489.1) 592.6
Amortization of intangibles —
 —
 1.2
 —
 1.2
Gross margin (a)
 $771.0
 $41.8
 $55.4
 $(3.5) $864.7
           
Depreciation and amortization $144.8
 $0.8
 $(5.8) $—
 $139.8
Goodwill impairment (Note 7) $—
 $—
 $135.8
 $—
 $135.8
Fixed asset impairment $—
 $—
 $11.5
 $—
 $11.5
Interest expense $33.9
 $0.5
 $92.9
 $(0.7) $126.6
Income tax expense / (benefit) $39.7
 $2.0
 $(23.5) $—
 $18.2
Net income / (loss) $115.0
 $3.2
 $(192.8) $—
 $(74.6)
           
Cash capital expenditures $114.2
 $2.5
 $1.4
 $—
 $118.1
           
Total assets (end of year) $3,338.7
 $94.9
 $1,440.1
 $(1,295.9) $3,577.8
$ in millions T&D Generation Other Adjustments and Eliminations 
DPL Consolidated
Year ended December 31, 2014
Revenues from external customers (b)
 $1,020.1
 $721.8
 $7.1
 $(32.5) $1,716.5
Intersegment revenues 1.7
 72.8
 3.8
 (78.3) —
Total revenues $1,021.8
 $794.6
 $10.9
 $(110.8) $1,716.5
           
Depreciation and amortization $75.5
 $75.3
 $(15.2) $—
 $135.6
Fixed asset impairment (Note 15) $—
 $—
 $11.5
 $—
 $11.5
Interest expense $29.8
 $5.0
 $92.5
 $(0.7) $126.6
Income / (loss) from continuing operations before income tax $241.7
 $(78.0) $(91.1) $—
 $72.6
           
Cash capital expenditures $100.4
 $14.5
 $3.2
 $—
 $118.1
           
Total assets (end of year) (a)
 $1,686.1
 $1,771.4
 $1,397.5
 $(1,295.9) $3,559.1

(a)For purposesIncludes assets held for sale related to the sale 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.DPLER.

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$ in millions Utility Competitive Retail Other Adjustments and Eliminations DPL Consolidated
Year ended December 31, 2013
Revenues from external customers $1,098.2
 $511.6
 $27.1
 $—
 $1,636.9
Intersegment revenues 453.3
 —
 4.0
 (457.3) —
Total revenues 1,551.5
 511.6
 31.1
 (457.3) 1,636.9
           
Fuel 362.5
 —
 4.2
 —
 366.7
Purchased power 381.9
 459.7
 1.1
 (453.7) 389.0
Amortization of intangibles —
 —
 7.1
 —
 7.1
Gross margin (a)
 $807.1
 $51.9
 $18.7
 $(3.6) $874.1
           
Depreciation and amortization $140.2
 $0.6
 $(7.9) $—
 $132.9
Goodwill impairment (Note 7) $—
 $—
 $306.3
 $—
 $306.3
Fixed asset impairment $86.0
 $—
 $(59.8) $—
 $26.2
Interest expense $37.2
 $0.5
 $86.9
 $(0.6) $124.0
Income tax expense / (benefit) $18.6
 $4.2
 $(0.5) $—
 $22.3
Net income / (loss) $83.6
 $6.6
 $(312.2) $—
 $(222.0)
      $—
    
Cash capital expenditures $122.1
 $—
 $2.3
 $—
 $124.4
           
Total assets (end of year) $3,313.1
 $105.0
 $1,675.8
 $(1,372.4) $3,721.5

(a)(b)For purposesWholesale revenue for 2014 was not restated for the impact of discussing operating results, we presentnetting between wholesale revenue and discuss gross margins. This format is useful to investorspurchased power for the Generation segment because it allows analysiswas impracticable to restate. This impacts the Generation revenue as well as the revenue in the Adjustments and comparabilityEliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. In addition, wholesale revenue for the T&D segment in 2014 includes OVEC revenue of operating trends$32.5 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and includesEliminations column in the same information that is used by management to make decisions regarding our financial performance.table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax.

Note 15 – Fixed-asset Impairment

During the years ended December 31, 2016, 2015 and 2014, DPL had the following fixed-asset impairments:
  Years ended December 31,
  2015 2014 2013
East Bend (DP&L)
 $—
 $11.5
 $—
Conesville (DP&L)
 —
 —
 26.2
Total fixed-asset impairment expense $—
 $11.5
 $26.2
    Years ended December 31,
  Measurement Date 2016 2015 2014
Killen December 31, 2016 $75.4
 $—
 $—
Stuart December 31, 2016 228.5
 —
 —
Miami Fort December 31, 2016 149.4
 —
 —
Zimmer December 31, 2016 144.7
 —
 —
Conesville December 31, 2016 23.9
 —
 —
Hutchings peaking facilities December 31, 2016 1.6
 —
 —
Killen June 30, 2016 230.8
 —
 —
Certain peaking facilities June 30, 2016 4.7
 —
 —
East Bend March 31, 2014 —
 —
 11.5
         
Total impairment loss   $859.0
 $—
 $11.5

Killen, Stuart, Miami Fort, Zimmer, Conesville and Hutchings, December 31, 2016 - During the fourth quarter of 2016, we tested the recoverability of our long-lived coal-fired generation assets and one gas-fired peaking plant. Additional uncertainty around the useful life of Stuart and Killen related to the DP&L ESP proceedings along with lower expectations of forward dark spreads and capacity prices beyond the cleared period were collectively determined to be an impairment indicator for these assets. Market information indicating that there was a significant decrease in the fair value of Zimmer and Miami Fort was determined to be an indicator of impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the gas-fired peaking plant, significant incremental capital expenditures relative to its fair value along with the fact that an impairment charge was previously taken at this facility in Q2 2016, were collectively determined to be an impairment indicator for this asset. DP&L performed a long-lived asset impairment analysis for each of these asset

groups and determined that their carrying amounts were not recoverable. The Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups and the Hutchings gas-fired peaking plant asset group were determined to have a fair value of $42.8 million, $57.4 million, $36.5 million, $23.7 million, $1.1 million and $1.6 million, respectively, using the market approach for Miami Fort and Zimmer and the income approach for the remaining asset groups. As a result, DPL recognized a total pre-tax asset impairment expense of $623.5 million.

Killen and DP&L peaking facilities, June 30, 2016 - During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amounts of Killen and certain DP&L peaking generating facilities were not recoverable. The asset groups of Killen and these DP&L peaking generating facilities were determined to have fair values of $84.3 million and $5.2 million, respectively, using the discounted cash flows under the income approach. As a result, DPL recognized an asset impairment expense of $230.8 million and $4.7 million for Killen and these DP&L peaking generating facilities, respectively.

East Bend, (DP&L)March 31, 2014- - During the first quarter of 2014, DPL tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L. Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach. As a result, we recognized an asset impairment expense of $11.5 million. East Bend is reported in the UtilityT&D segment, however, this impairment is shown within Other in Note 14 – Business Segments due to acquisition adjustments at DPL which were not pushed down to the utility segment.T&D or Generation segments. In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend. This transaction closed on December 30, 2014.

Conesville (DP&L) - During the fourth quarter of 2013, DPL tested the recoverability of the long-lived assets at Conesville, a 129 MW coal-fired station in Ohio jointly-owned by DP&L. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit failing step 1 of the annual goodwill impairment test were determined to be an impairment indicator for long-lived assets. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The long-lived asset group subject to the impairment evaluation was determined to be each individual station of

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DP&L. This determination was based on the assessment of the stations’ ability to generate independent cash flows. The Conesville asset group was determined to have zero fair value using discounted cash flows under the income approach. As a result, DPL recognized an asset impairment expense of $26.2 million. Conesville is reported in the Utility segment.

Note 16 – Discontinued Operations

On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015 and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. This amount iswas shown as Restricted cash with the associated liability shown as "Deposit received on sale of DPLER" on the Consolidated Balance Sheet as of December 31, 2015. As the cash received was restricted upon receipt, it is not included within the Statement of Cash Flows. Assets and liabilities related to DPLER have beenwere reclassified to "Assets held for sale" and "Liabilities held for sale" in the December 31, 2015 and 2014Consolidated Balance Sheets. We expect to recordSheet. DPL recorded a gain on this transaction of approximately $56.0$49.2 million net of tax, in the first quarter of 2016. The gain includes the impact of deferred taxes and DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation at December 31, 2015 and 2014.2015. Deferred taxes and intercompany balances were not reclassified to held for sale.

Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Consolidated Statements of Operations for the years ended December 31, 2016, 2015 2014 and 2013.2014.


The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:
$ in millions December 31,   December 31,    
 2015 2014   2015    
Accounts receivable, net $31.0
 $64.4
   $31.0
    
Property, plant & equipment, net 4.6
 4.9
   1.1
    
Intangible assets, net 24.6
 29.6
   28.1
    
Other assets 2.0
 2.9
   2.0
    
Total assets of the disposal group classified as held for sale in the balance sheets $62.2
 $101.8
 
 $62.2
    
            
Accounts payable $0.8
 $14.8
   $0.8
    
Other liabilities 0.8
 2.5
   0.8
    
Total liabilities of the disposal group classified as held for sale in the balance sheets $1.6
 $17.3
 
 $1.6
    
            
 Years ended December 31, Years ended December 31,
 2015 2014 2013 2016 2015 2014
Revenues $340.9
 $533.6
 $511.6
 $—
 $340.9
 $533.6
Cost of revenues (307.0) (493.0) (466.8) —
 (307.0) (493.0)
Operating expenses (22.5) (34.0) (38.8) (0.7) (22.5) (34.0)
Goodwill impairment —
 (135.8) —
 —
 —
 (135.8)
Profit / (loss) of discontinued operations before income taxes 11.4
 (129.2) 6.0
 (0.7) 11.4
 (129.2)
Income tax benefit / (expense) (1.0) 2.6
 2.4
Gain from disposal of discontinued operations 49.2
 —
 —
Income tax expense / (benefit) 19.2
 (1.0) 2.6
Income / (loss) on discontinued operations $12.4
 $(131.8) $3.6
 $29.3
 $12.4
 $(131.8)

DPLER purchased its power from DP&L during the periods presented. Prior to DPLER being presented as a discontinued operation, this purchased power and DP&L's corresponding wholesale revenue would have been eliminated in consolidation.


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Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million, $35.8 million $29.6 million and $(7.7)$29.6 million for the years ended December 31, 2016, 2015 2014 and 2013,2014, respectively. Cash flows from investing activities for discontinued operations were $75.5 million, $0.5 million $(2.2) million and $(2.0)$(2.2) million for the years ended December 31, 2016, 2015 2014, and 2013,2014, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented.

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FINANCIAL STATEMENTS

The Dayton Power and Light Company

70
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Report of Independent Registered Public Accounting Firm



To theThe Board of Directors of The Dayton Power and& Light Company

We have audited the accompanying balance sheets of The Dayton Power and& Light Company (DP&L) as of December 31, 20152016 and 2014,2015, and the related statements of operations, comprehensive income,income/(loss), cash flows and shareholder’s equity for each of the three years in the period ended December 31, 2015.2016. Our auditaudits also included the financial statement schedule “Schedule II - Valuation and Qualifying Accounts” for each of the three years in the period ended December 31, 2015.2016. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our auditsDecember 31, 2016 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. We conducted our December 31, 2015 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,statements. An audit also includes assessing the accounting principles used and significant estimates made by management, andas well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DP&LThe Dayton Power & Light Company at December 31, 20152016 and 2014,2015, and the results of itstheir operations and itstheir cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.


/s/ Ernst & Young LLP

February 23, 2016
Indianapolis, Indiana
February 24, 2017


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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF OPERATIONS
  Years ended December 31,
$ in millions 2015 2014 2013
Revenues $1,552.3
 $1,668.3
 $1,551.5
Cost of revenues:      
Fuel 244.7
 314.9
 362.5
Purchased power 555.7
 582.4
 381.9
Total cost of revenues 800.4
 897.3
 744.4
       
Gross margin 751.9
 771.0
 807.1
Operating expenses:      
Operation and maintenance 350.5
 355.2
 364.2
Depreciation and amortization 138.2
 144.8
 140.2
General taxes 85.0
 85.7
 74.3
Fixed asset impairment —
 —
 86.0
Other 0.4
 (3.5) 2.5
Total operating expenses 574.1
 582.2
 667.2
       
Operating income 177.8
 188.8
 139.9
       
Other income / (expense), net      
Investment income 0.3
 0.9
 2.0
Interest expense (30.9) (33.9) (37.2)
Charge for early redemption of debt (5.0) —
 —
Other deductions (0.7) (1.1) (2.5)
Other expense, net (36.3) (34.1) (37.7)
       
Earnings from operations before income tax 141.5
 154.7
 102.2
       
Income tax expense 35.1
 39.7
 18.6
       
Net income 106.4
 115.0
 83.6
       
Dividends on preferred stock 0.9
 0.9
 0.9
       
Earnings attributable to common stock $105.5
 $114.1
 $82.7

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
  Years ended December 31,
$ in millions 2015 2014 2013
Net income $106.4
 $115.0
 $83.6
Available-for-sale securities activity:      
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.1, $0.2 and $0.9 for each respective period (0.2) (0.3) (1.6)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, ($0.2) and ($0.7) for each respective period —
 0.2
 1.4
Total change in fair value of available-for-sale securities (0.2) (0.1) (0.2)
Derivative activity:      
Change in derivative fair value, net of income tax benefit / (expense) of ($10.3), $10.5 and ($0.6) for each respective period 18.2
 (18.8) 1.0
Reclassification of earnings, net of income tax benefit / (expense) of $5.6, ($11.5) and ($2.5) for each respective period (9.8) 15.4
 2.6
Total change in fair value of derivatives 8.4
 (3.4) 3.6
Pension and postretirement activity:      
Prior service cost for the period, net of income tax benefit / (expense) of $0.0, $1.3 and ($0.2) for each respective period —
 (2.3) 0.5
Net loss for the period, net of income tax benefit / (expense) of ($1.0), $7.2 and ($1.9) for each respective period 1.7
 (12.5) 4.3
Reclassification to earnings, net of income tax benefit / (expense) of ($1.9), ($1.5) and ($1.9) for each respective period 3.7
 2.7
 3.8
Total change in unfunded pension and postretirement obligation 5.4
 (12.1) 8.6
Other comprehensive income / (loss) 13.6
 (15.6) 12.0
       
Net comprehensive income $120.0
 $99.4
 $95.6
THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF OPERATIONS
  Years ended December 31,
$ in millions 2016 2015 2014
Revenues $1,365.9
 $1,552.3
 $1,668.3
Cost of revenues:      
Fuel 248.9
 244.7
 314.9
Purchased power 414.1
 555.7
 582.4
Total cost of revenues 663.0
 800.4
 897.3
       
Gross margin 702.9
 751.9
 771.0
Operating expenses:      
Operation and maintenance 343.2
 350.5
 355.2
Depreciation and amortization 120.3
 138.2
 144.8
General taxes 83.8
 85.0
 85.7
Gain on termination of contract (27.7) —
 —
Fixed-asset impairment 1,353.5
 —
 —
Other (0.1) 0.4
 (3.5)
Total operating expenses 1,873.0
 574.1
 582.2
       
Operating income / (loss) (1,170.1) 177.8
 188.8
       
Other income / (expense), net      
Investment income 0.4
 0.3
 0.9
Interest expense (24.5) (30.9) (33.9)
Charge for early redemption of debt (0.5) (5.0) —
Other deductions (0.4) (0.7) (1.1)
Other expense, net (25.0) (36.3) (34.1)
       
Income / (loss) from operations before income tax (1,195.1) 141.5
 154.7
       
Income tax expense / (benefit) (422.4) 35.1
 39.7
       
Net income / (loss) (772.7) 106.4
 115.0
       
Dividends on preferred stock 0.7
 0.9
 0.9
       
Income / (loss) attributable to common stock $(773.4) $105.5
 $114.1

See Notes to Financial Statements.


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THE DAYTON POWER AND LIGHT COMPANY
BALANCE SHEETS
$ in millions December 31, 2015 December 31, 2014
ASSETS    
Current assets:    
Cash and cash equivalents $5.4
 $5.4
Restricted cash 44.8
 16.7
Accounts receivable, net (Note 2) 119.5
 152.7
Inventories (Note 2) 108.0
 99.0
Taxes applicable to subsequent years 79.2
 75.4
Regulatory assets, current (Note 3) 14.4
 44.2
Other prepayments and current assets 48.1
 41.1
Total current assets 419.4
 434.5
     
Property, plant and equipment:    
Property, plant and equipment 5,244.7
 5,120.7
Less: Accumulated depreciation and amortization (2,584.0) (2,495.7)
  2,660.7
 2,625.0
Construction work in process 78.0
 75.4
Total net property, plant and equipment 2,738.7
 2,700.4
Other non-current assets:    
Regulatory assets, non-current (Note 3) 179.9
 167.5
Intangible assets, net of amortization (Note 1) 5.0
 7.8
Other deferred assets 22.8
 28.5
Total other non-current assets 207.7
 203.8
Total Assets $3,365.8
 $3,338.7
     
LIABILITIES AND SHAREHOLDER'S EQUITY    
Current liabilities:    
Current portion - long-term debt (Note 7) $444.9
 $0.1
Short-term debt 35.0
 —
Accounts payable 94.1
 104.8
Accrued taxes 86.2
 82.6
Accrued interest 4.1
 9.8
Customer security deposits 15.1
 34.5
Regulatory liabilities, current (Note 3) 24.4
 4.4
Other current liabilities 51.0
 44.8
Advance on contract termination 27.7
 —
Total current liabilities 782.5
 281.0
     
Non-current liabilities:    
Long-term debt (Note 7) 318.0
 877.0
Deferred taxes (Note 8) 631.2
 650.0
Taxes payable 82.1
 78.4
Regulatory liabilities, non-current (Note 3) 127.0
 124.1
Pension, retiree and other benefits (Note 9) 87.1
 95.9
Unamortized investment tax credit 20.0
 22.4
Other deferred credits 82.3
 43.6
Total non-current liabilities 1,347.7
 1,891.4
     
Redeemable preferred stock of subsidiary (Note 10) 22.9
 22.9
     
Commitments and contingencies (Note 11) 
 
     
Common shareholder's equity:    
Common stock, par value of $0.01 per share 0.4
 0.4
250,000,000 shares authorized, 41,172,173 shares issued and outstanding    
Other paid-in capital 803.7
 803.5
Accumulated other comprehensive loss (28.7) (42.3)
Retained earnings 437.3
 381.8
Total common shareholder's equity 1,212.7
 1,143.4
     
Total Liabilities and Shareholder's Equity $3,365.8
 $3,338.7
THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
  Years ended December 31,
$ in millions 2016 2015 2014
Net income / (loss) $(772.7) $106.4
 $115.0
Available-for-sale securities activity:      
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of ($0.1), $0.1 and $0.2 for each respective period 0.2
 (0.2) (0.3)
Reclassification to earnings, net of income tax benefit / (expense) of $0.0, $0.0 and ($0.2) for each respective period —
 —
 0.2
Total change in fair value of available-for-sale securities 0.2
 (0.2) (0.1)
Derivative activity:      
Change in derivative fair value, net of income tax benefit / (expense) of ($8.7), ($10.3) and $10.5 for each respective period 16.1
 18.2
 (18.8)
Reclassification to earnings, net of income tax benefit / (expense) of $16.4, $5.6 and ($11.5) for each respective period (30.0) (9.8) 15.4
Total change in fair value of derivatives (13.9) 8.4
 (3.4)
Pension and postretirement activity:      
Prior service cost for the period, net of income tax benefit / (expense) of $0.0, $0.0 and $1.3 for each respective period (0.1) —
 (2.3)
Net gain / (loss) for the period, net of income tax benefit / (expense) of $1.1, ($1.0) and $7.2 for each respective period (5.9) 1.7
 (12.5)
Reclassification to earnings, net of income tax benefit / (expense) of ($1.8), ($1.9) and ($1.5) for each respective period 5.9
 3.7
 2.7
Total change in unfunded pension and postretirement obligations (0.1) 5.4
 (12.1)
Other comprehensive income / (loss) (13.8) 13.6
 (15.6)
       
Net comprehensive income / (loss) $(786.5) $120.0
 $99.4

See Notes to Financial Statements.


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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF CASH FLOWS
  Years ended December 31,
$ in millions 2015 2014 2013
Cash flows from operating activities:      
Net income $106.4
 $115.0
 $83.6
Adjustments to reconcile Net income (loss) to Net cash from operating activities      
Depreciation and amortization 138.2
 144.8
 140.2
Amortization of deferred financing costs 2.9
 3.1
 1.5
Unrealized loss (gain) on derivatives 5.7
 2.1
 1.3
Deferred income taxes (19.2) 7.5
 (16.8)
Fixed-asset impairment —
 —
 86.0
Loss / (Gain) on asset disposal 0.4
 (3.5) 2.5
Changes in certain assets and liabilities:      
Accounts receivable 28.7
 (7.1) 15.0
Inventories (9.1) (24.6) 27.2
Prepaid taxes (1.3) (1.1) 0.4
Taxes applicable to subsequent years (3.7) (6.9) (1.8)
Deferred regulatory costs, net 21.8
 5.4
 7.8
Accounts payable (5.8) 32.4
 (5.9)
Accrued taxes payable 7.3
 9.0
 (9.1)
Accrued interest payable (5.7) 0.1
 (3.4)
Other current and deferred liabilities (9.3) (18.1) 5.9
Pension, retiree and other benefits (0.7) 19.1
 1.8
Unamortized investment tax credit (2.4) (2.5) (2.5)
Other 2.5
 (23.0) 1.6
Net cash from operating activities 256.7
 251.7
 335.3
       
Cash flows from investing activities:      
Capital expenditures (127.0) (114.2) (122.1)
Decrease / (increase) in restricted cash (0.3) (3.7) (2.3)
Purchase of renewable energy credits (0.8) (3.5) (3.9)
Proceeds from sale of property —
 10.7
 0.8
Insurance proceeds 5.2
 0.9
 14.2
Other investing activities, net 0.4
 1.3
 (1.2)
Net cash from investing activities (122.5) (108.5) (114.5)
       
Cash flows from financing activities      
Dividends paid on common stock to parent (50.0) (159.0) (190.0)
Dividends paid on preferred stock (0.9) (0.9) (0.9)
Retirement of long-term debt (314.4) (0.1) (470.1)
Issuance of long-term debt 200.0
 —
 445.0
Deferred financing costs (3.9) (0.7) (10.4)
Borrowings from revolving credit facilities 50.0
 —
 —
Repayment of borrowings from revolving credit facilities (50.0) —
 —
Borrowings from related party 35.0
 15.0
 —
Repayment of borrowings from related party —
 (15.0) —
Net cash from financing activities (134.2) (160.7) (226.4)
       
Cash and cash equivalents:      
Net increase / (decrease) in cash —
 (17.5) (5.6)
Balance at beginning of period 5.4
 22.9
 28.5
Cash and cash equivalents at end of period $5.4
 $5.4
 $22.9
Supplemental cash flow information:      
Interest paid, net of amounts capitalized $27.5
 $26.6
 $41.5
Income taxes (refunded) / paid, net $0.8
 $0.7
 $(20.3)
       
Non-cash financing and investing activities:      
Accruals for capital expenditures $16.9
 $16.3
 $14.7
THE DAYTON POWER AND LIGHT COMPANY
BALANCE SHEETS
$ in millions December 31, 2016 December 31, 2015
ASSETS    
Current assets:    
Cash and cash equivalents $1.6
 $5.4
Restricted cash 29.0
 44.8
Accounts receivable, net (Note 2) 134.6
 119.5
Inventories (Note 2) 75.8
 108.0
Taxes applicable to subsequent years 79.2
 79.2
Regulatory assets, current (Note 3) 0.1
 14.4
Other prepayments and current assets 32.4
 46.3
Total current assets 352.7
 417.6
     
Property, plant and equipment:    
Property, plant and equipment 2,398.6
 5,172.3
Less: Accumulated depreciation and amortization (1,047.9) (2,534.8)
  1,350.7
 2,637.5
Construction work in process 89.9
 76.5
Total net property, plant and equipment 1,440.6
 2,714.0
Other non-current assets:    
Regulatory assets, non-current (Note 3) 203.9
 179.9
Intangible assets, net of amortization 23.0
 29.7
Other deferred assets 14.9
 18.4
Total other non-current assets 241.8
 228.0
Total Assets $2,035.1
 $3,359.6
     
LIABILITIES AND SHAREHOLDER'S EQUITY    
Current liabilities:    
Current portion - long-term debt (Note 7) $4.7
 $443.1
Short-term debt 5.0
 35.0
Accounts payable 110.5
 94.1
Accrued taxes 75.7
 86.2
Accrued interest 2.1
 4.1
Customer security deposits 15.2
 15.1
Regulatory liabilities, current (Note 3) 33.7
 24.4
Other current liabilities 48.3
 51.0
Advance on contract termination —
 27.7
Total current liabilities 295.2
 780.7
     
Non-current liabilities:    
Long-term debt (Note 7) 744.7
 313.6
Deferred taxes (Note 8) 146.3
 631.2
Taxes payable 84.1
 82.1
Regulatory liabilities, non-current (Note 3) 130.4
 127.0
Pension, retiree and other benefits (Note 9) 101.6
 87.1
Unamortized investment tax credit 17.7
 20.0
Asset retirement obligations 135.2
 62.1
Other deferred credits 17.6
 20.2
Total non-current liabilities 1,377.6
 1,343.3
     
Redeemable preferred stock of subsidiary (Note 10) —
 22.9
     
Commitments and contingencies (Note 11) 
 
     
Common shareholder's equity:    
Common stock, par value of $0.01 per share 0.4
 0.4
250,000,000 shares authorized, 41,172,173 shares issued and outstanding    
Other paid-in capital 810.7
 803.7
Accumulated other comprehensive loss (42.5) (28.7)
Retained earnings / (accumulated deficit) (406.3) 437.3
Total common shareholder's equity 362.3
 1,212.7
     
Total Liabilities and Shareholder's Equity $2,035.1
 $3,359.6

See Notes to Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF SHAREHOLDER'S EQUITY
  
Common Stock (a)
        
$ in millions (except Outstanding Shares) Outstanding Shares Amount Other Paid-in Capital Accumulated Other Comprehensive Income / (Loss) Retained Earnings Total
Beginning balance 41,172,173
 $0.4
 $803.3
 $(38.7) $534.1
 $1,299.1
Year ended December 31, 2013            
Net comprehensive income       12.0
 83.6
 95.6
Common stock dividends         (190.0) (190.0)
Preferred stock dividends         (0.9) (0.9)
Other     0.2
   —
 0.2
Ending balance 41,172,173
 0.4
 803.5
 (26.7) 426.8
 1,204.0
Year ended December 31, 2014            
Net comprehensive income       (15.6) 115.0
 99.4
Common stock dividends         (159.0) (159.0)
Preferred stock dividends         (0.9) (0.9)
Other     

   (0.1) (0.1)
Ending balance 41,172,173
 0.4
 803.5
 (42.3) 381.8
 1,143.4
Year ended December 31, 2015            
Net comprehensive income       13.6
 106.4
 120.0
Common stock dividends         (50.0) (50.0)
Preferred stock dividends         (0.9) (0.9)
Other     0.2
   

 0.2
Ending balance 41,172,173
 $0.4
 $803.7
 $(28.7) $437.3
 $1,212.7
THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF CASH FLOWS
  Years ended December 31,
$ in millions 2016 2015 2014
Cash flows from operating activities:      
Net income / (loss) $(772.7) $106.4
 $115.0
Adjustments to reconcile Net income (loss) to Net cash from operating activities      
Depreciation and amortization 120.3
 138.2
 144.8
Amortization of deferred financing costs 2.9
 2.9
 3.1
Unrealized loss (gain) on derivatives (4.2) 5.7
 2.1
Deferred income taxes (477.5) (19.2) 7.5
Fixed-asset impairment 1,353.5
 —
 —
Loss / (Gain) on asset disposal —
 0.4
 (3.5)
Changes in certain assets and liabilities:      
Accounts receivable (9.7) 28.7
 (7.1)
Inventories 32.2
 (9.1) (24.6)
Prepaid taxes 2.7
 (1.3) (1.1)
Taxes applicable to subsequent years —
 (3.7) (6.9)
Deferred regulatory costs, net 4.1
 21.8
 5.4
Accounts payable 16.0
 (5.8) 32.4
Accrued taxes payable (10.5) 7.3
 9.0
Accrued interest payable (2.0) (5.7) 0.1
Other current and deferred liabilities (1.8) (9.3) (18.1)
Pension, retiree and other benefits 8.6
 (0.7) 19.1
Unamortized investment tax credit (2.3) (2.4) (2.5)
Other 5.2
 2.5
 (23.0)
Net cash provided by operating activities 264.8
 256.7
 251.7
       
Cash flows from investing activities:      
Capital expenditures (128.3) (127.0) (114.2)
Increase in restricted cash (11.9) (0.3) (3.7)
Purchase of renewable energy credits (0.4) (0.8) (3.5)
Proceeds from sale of property —
 —
 10.7
Insurance proceeds 6.1
 5.2
 0.9
Other investing activities, net 1.1
 0.4
 1.3
Net cash used in investing activities (133.4) (122.5) (108.5)
       
Cash flows from financing activities      
Dividends paid on common stock to parent (70.0) (50.0) (159.0)
Dividends paid on preferred stock (0.7) (0.9) (0.9)
Retirement of long-term debt (445.3) (314.4) (0.1)
Issuance of long-term debt 442.8
 200.0
 —
Deferred financing costs (8.5) (3.9) (0.7)
Redemption on preferred stock (23.5) —
 —
Borrowings from revolving credit facilities —
 50.0
 —
Repayment of borrowings from revolving credit facilities —
 (50.0) —
Borrowings from related party 10.0
 35.0
 15.0
Repayment of borrowings from related party (40.0) —
 (15.0)
Net cash used in financing activities (135.2) (134.2) (160.7)
       
Cash and cash equivalents:      
Net increase / (decrease) in cash (3.8) —
 (17.5)
Balance at beginning of period 5.4
 5.4
 22.9
Cash and cash equivalents at end of period $1.6
 $5.4
 $5.4
Supplemental cash flow information:      
Interest paid, net of amounts capitalized $21.4
 $27.5
 $26.6
Income taxes (refunded) / paid, net $0.3
 $0.8
 $0.7
       
Non-cash financing and investing activities:      
Accruals for capital expenditures $14.8
 $16.9
 $16.3
Equity contribution to settle liability $7.5
 $—
 $—

See Notes to Financial Statements.

THE DAYTON POWER AND LIGHT COMPANY
STATEMENTS OF SHAREHOLDER'S EQUITY
  
Common Stock (a)
        
$ in millions (except Outstanding Shares) Outstanding Shares Amount Other Paid-in Capital Accumulated Other Comprehensive Income / (Loss) Retained Earnings / Accumulated Deficit Total
Beginning balance 41,172,173
 $0.4
 $803.5
 $(26.7) $426.8
 $1,204.0
Year ended December 31, 2014            
Net comprehensive income       (15.6) 115.0
 99.4
Common stock dividends         (159.0) (159.0)
Preferred stock dividends         (0.9) (0.9)
Other     

   (0.1) (0.1)
Ending balance 41,172,173
 0.4
 803.5
 (42.3) 381.8
 1,143.4
Year ended December 31, 2015            
Net comprehensive income       13.6
 106.4
 120.0
Common stock dividends         (50.0) (50.0)
Preferred stock dividends         (0.9) (0.9)
Other     0.2
   

 0.2
Ending balance 41,172,173
 0.4
 803.7
 (28.7) 437.3
 1,212.7
Year ended December 31, 2016            
Net comprehensive loss       (13.8) (772.7) (786.5)
Common stock dividends         (70.0) (70.0)
Preferred stock dividends         (0.7) (0.7)
Other     7.0
   (0.2) 6.8
Ending balance 41,172,173
 $0.4
 $810.7
 $(42.5) $(406.3) $362.3

(a)$0.01 par value, 250,000,000 shares authorized.

See Notes to Financial Statements.

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The Dayton Power and Light Company
Notes to Financial Statements
For the years ended December 31, 2016, 2015 2014 and 20132014

Note 1 – Overview and Summary of Significant Accounting Policies

Description of Business
DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribution and transmission services are still regulated. DP&L has the exclusive right to provide such service to its approximately 517,000519,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer supplied 100%January 2016, all of the generationelectric supply for SSO customers and starting January 2016, SSO is now 100% competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the generalgeneral economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. Through December 31, 2015, DP&L&L's generation was also used to provide electricity to its SSO customers, as it transitioned to a competitive bidding structure in 2014 and 2015, and also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of itsDPLER's retail customers.

In accordance withDP&L has two segments, the ESP Order, onT&D segment and the Generation segment. See Note 13 – Business Segments for more information relating to reportable segments.

On December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014, the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L is required to sell or transfer its generation assets by January 1, 2017 and continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale.

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

DP&L employed 1,1891,160 people at January 31, 2016.2017. Approximately 61%63% of all employees are under a collective bargaining agreement which expires on October 31, 2017.

Financial Statement Presentation
DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements.

We have evaluated subsequent events through the date this report is issued.

Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation. See “Intangibles” below for additional information.

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


Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where

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electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.

All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.

Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.0$2.7 million, $1.5$2.0 million, and $1.5 million for the years ended December 31, 2016, 2015 2014 and 2013,2014, respectively.

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

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

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

Repairs and Maintenance
Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 2.6%4.6% in 2016, 2.5% in 2015 and 2.8% in 2014 and 4.4% in 2013.2014. Depreciation was $110.0 million, $132.7 million $141.6 million and $136.5$141.6 million for the years ended December 31, 2016, 2015 and 2014, and 2013, respectively.


During the fourth quarter of 2015, DP&L tested the recoverability of long-lived assets at certain generating stations. See Note 1312 – Fixed-asset ImpairmentRelated Party Transactions for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator.

Regulatory Accounting
As a regulated utility, we apply the provisions of FASC 980 “Regulated“Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred

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costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.

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

Inventories
Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.

Intangibles
Intangibles include software, 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 cost 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 on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired.

Intangible assets include capitalized software of $78.5 million and $73.9 million and its corresponding amortization of $56.4 million and $49.2 million previously classified within Total net property, plant and equipment that were reclassified to Intangible assets as of December 31, 2016 and 2015, respectively. These assets are amortized over seven years. See “New Accounting Pronouncements” below for additional information. Amortization expense was $7.5 million, $8.2 million and $8.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. The estimated amortization expense of this internal-use software is $15.3 million ($6.1 million in 2017, $5.6 million in 2018 and $3.6 million in 2019).

Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Statement of Operations.

Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful

lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Assets and LiabilitiesMatters for additional information.

DPLand its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 – Income Taxes for additional information.

Financial Instruments
We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’shareholder's equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.


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Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2016, 2015 and 2014 and 2013 were $50.9 million, $49.9 million $50.8 million and $50.5$50.8 million, respectively.

Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the January 1, 2016 contract termination canceling DP&L's power sales contracts with DPLER. See Note 14 – Subsequent Event for additional information regarding this contract termination.

Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information.

Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, other DPL subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. DP&L is responsible for claim costs below certain coverage thresholds of MVIC and third party insurers for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and disabilityother reserves for claims costs below certain coverage thresholds of MVIC and third-party providers. We recorded these additional insurance and claims costs of approximately $13.7$11.8 million and $15.6$13.7 million at December 31, 20152016 and 2014,2015, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss

estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Pension and Postretirement Benefits
We recognize, in our Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

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Effective January 1, 2016, we will applyapplied a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of ASCFASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.

The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015 or 2016, nor will it impact future remeasurements. This change in approach will impactimpacted the service cost and interest cost recorded in 2016 and will impact future years. It will also impactimpacted the actuarial gains and losses recorded in 2016 and will impact future years, as well as the amortization thereof.

The expected 2016 service costs and interest costs included in Note 9 – Benefit Plans reflect the change in methodology described above. The impact of the change in approach on expected service costs and interest costs in 2016 is shown below:
$ in millions Expected 2016 Service Cost Expected 2016 Interest Cost 2016 Service Cost 2016 Interest Cost
 Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change Disaggregated rate approach Aggregate rate approach Impact of change
Total Pension $5.7
 $6.1
 $(0.4) $14.8
 $17.9
 $(3.1) $5.7
 $6.1
 $(0.4) $14.7
 $17.9
 $(3.2)
Total Postretirement Benefits $0.2
 $0.2
 $—
 $0.6
 $0.7
 $(0.1) 0.2
 0.2
 —
 0.6
 0.7
 (0.1)
Total $5.9
 $6.3
 $(0.4) $15.4
 $18.6
 $(3.2) $5.9
 $6.3
 $(0.4) $15.3
 $18.6
 $(3.3)

See Note 9 – Benefit Plans for more information.

Related Party Transactions
In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES.

See Note 12 – Related Party Transactions for additional information on Related Party Transactions.


New accounting pronouncements adopted

ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet ClassificationThe following table provides a brief description of Deferred Taxes
Effective December 31, 2015, we prospectively adopted ASU No. 2015-17, which requiresrecent accounting pronouncements that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now onlycould have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As we elected to apply this ASU prospectively, prior periods were not adjusted.

ASU No. 2015-13, Derivatives and Hedging (Topic 815):Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Market
In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815, Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As we had designated qualifying contracts as normal purchase or normal sales, there was no impact on our financial statements upon adoption of this standard.


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Accounting pronouncements issued but not yet effective

ASU No. 2016-01, Financial Instruments — Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. We are currently evaluating the applicability and materiality of the standard, but we do not anticipate a material impact on our financial statements:
Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Adopted
2016-19 - Technical Corrections and Improvements
This standard clarifies guidance that affects the implementation of ASU 2015-05. It clarifies that the license of internal-use software shall be accounted for as the acquisition of an intangible asset. Transition method: retrospective.

The adoption of the new guidance did not have an impact on net income, net assets or net equity.		December 31, 2016Capitalized software of $78.5 million and its corresponding amortization of $56.4 million previously classified within property, plant and equipment were reclassified to intangibles as of December 31, 2016.
2015-15, Interest - Imputation of Interest (Subtopic 835-30)Given the absence of authoritative guidance within ASU 2015-03, this standard clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Transition method: retrospective.January 1, 2016Deferred financing costs related to lines-of-credit of approximately $0.7 million recorded within Other deferred assets were not reclassified.
2015-03, Interest - Imputation of Interest (Subtopic 835-30)The standard simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the standard. Transition method: retrospective.January 1, 2016Deferred financing costs of approximately $1.8 million previously classified within Other prepayments and current assets and $4.5 million previously classified within Other deferred assets were reclassified to reduce the related debt liabilities.
2015-02, Consolidation (Topic 810): Amendments to the Consolidation AnalysisThe standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. Transition method: retrospective.January 1, 2016There were no changes to the consolidation conclusions.
2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40)The standard requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.December 31, 2016Adoption of this standard had no impact on our financial statements.

Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill ImpairmentThis standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value.January 1, 2020. Early adoption is permitted as of January 1, 2017.We are currently evaluating the impact of adopting the standard on our financial statements.
2017-01, Business Combinations (Topic 805): Clarifying the Definition of a BusinessThis standard provides guidance to assist the entities with evaluating when a set of transferred assets and activities is a business.January 1, 2018. Early adoption is permittedWe are currently evaluating the impact of adopting the standard on our financial statements.
2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.January 1, 2018 Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our financial statements.
2016-17, Consolidation (Topic 810): Interest Held Through Related Parties That are Under Common ControlStates that businesses deciding whether they are primary beneficiaries can consider indirect interests held through related parties that are under common control on a proportionate basis as opposed to in their entirety.January 1, 2017 Early adoption is permitted.Transition is retrospective to all relevant prior periods beginning with the fiscal year in which ASU 2015-02 was initially applied.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than InventoryThis standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Transition method: modified retrospective.January 1, 2018. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our financial statements.
2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)This standard provides specific guidance on how certain cash transactions are presented and classified in the statement of cash flows. Transition method: retrospective.January 1, 2018. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our financial statements. We do not anticipate a material effect on our financial statements.
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial InstrumentsThe standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down. Transition method: various.January 1, 2020. Early adoption is permitted only as of January 1, 2019.We are currently evaluating the impact of adopting the standard on our financial statements. No transition method has been selected yet.
2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF MeetingRemoves some of the Emerging Issues Task Force (EITF) guidance for revenue recognition and hedge accounting from U.S. GAAP to reflect announcements the SEC staff made to the task force in March.January 1, 2018. Earlier application is permitted only as of January 1, 2017.We are currently evaluating the impact of adopting the standard on our financial statements.

Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment AccountingThe standard simplifies the following aspects of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.January 1, 2017. Early adoption is permitted.The primary effect of adoption will be the recognition of excess tax benefits in our provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized. We will continue to estimate the number of awards that are expected to vest in our determination of the related periodic compensation cost.
2016-06, Derivatives and Hedging (Topic 815) - Contingent Put and Call Options in Debt InstrumentsThis standard clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. When a call (put) option is contingently exercisable, an entity no longer has to assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. Transition method: a modified retrospective basis to existing debt instruments as of the effective date.January 1, 2017. Early adoption is permitted.We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2016-05, Derivatives and Hedging (Topic 815) - Effect of Derivative Contract Novations on Existing Hedge Accounting RelationshipsThe standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not require de-designation of that hedging relationship provided that all other hedge accounting criteria (including those in paragraphs 815-20-35-14 through 35-18) continue to be met. Transition method: prospective or a modified retrospective basis.January 1, 2017. Early adoption is permitted.We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements. No transition method has been selected yet.
2016-02, Leases (Topic 842)The standard creates Topic 842, Leases which supersedes Topic 840, Leases, and introduces a lessee model that brings substantially all leases onto the balance sheet while retaining most of the principles of the existing lessor model in U.S. GAAP and aligning many of those principles with Topic 606, Revenue from Contracts with Customers. Transition method: modified retrospective approach with certain practical expedients.January 1, 2019. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our financial statements.
2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial LiabilitiesThe standard significantly revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. Also, it amends certain disclosure requirements associated with the fair value of financial instruments. Transition: cumulative effect in Retained Earnings as of adoption or prospectively for equity investments without readily determinable fair value.January 1, 2018. Limited early adoption permitted.We are currently evaluating the impact of adopting the standard, but do not anticipate a material impact on our financial statements.
2015-11, Inventory (Topic 330): Simplifying the Measurement of InventoryThe standard replaces the current lower of cost or market test with a lower of cost or net realizable value test. Transition method: prospectively.January 1, 2017. Early adoption is permitted.We are currently evaluating the impact of adopting the standard on our financial statements.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, Revenue from Contracts with Customers (Topic 606),See discussion of the ASU below.January 1, 2018. Earlier application is permitted only as of January 1, 2017.We will adopt the standards on January 1, 2018; and we are currently evaluating the effect of their adoption on our financial statements.


ASU No. 2015-16, Business Combinations (Topic 805): Simplifying2014-09 and its subsequent corresponding updates provide the Accounting for Measurement-Period Adjustments
In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. We will adopt this standard on January 1, 2016, which is not expected to have a material impact on our

ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30)
In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015DP&L had approximately $6.3 million in deferred financing costs classified in other current and other non-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements
In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object toprinciples an entity presenting debt issuance costs relatedmust apply to line-of-credit arrangements as an asset thatmeasure and recognize revenue. The core principle is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, we had deferred financing costs related to lines of credit of approximately $0.7 million recorded within Other noncurrent assets that would not be reclassified upon adoption of this standard.

ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory
In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As we already used the net realizable value to make lower of cost or market determinations, there will be no impact on our financial statements upon adoption of this standard.


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ASU No. 2015-05, Intangibles – Goodwill and Other: Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. As all of our cloud computing arrangements will continue to be accounted for as service agreements, there will be no impact on our financial statements upon the adoption of this standard.

ASU No. 2014-05, Presentation of Financial Statements: Going Concern
The FASB recently issued ASU 2014-15 “Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016. ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.

ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity toshall recognize revenue to depict the transfer of promised goods or services to customers atin an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. In August 2015,Amendments to the FASBstandard were issued ASU No. 2015-14, Revenue from Contract with Customers (Topic 606): Deferralthat provide further clarification of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017principle and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities).to provide certain transition expedients. The standard permitswill replace most existing revenue recognition guidance in GAAP, including the useguidance on recognizing other income upon the sale or transfer of nonfinancial assets (including in-substance real estate).

The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach.approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. We have not yet selected a transition method and are currently evaluating the impact ofworking towards adopting the standard using the full retrospective method. However, we will continue to assess this conclusion which is dependent on ourthe final impact to the financial statements.

ASU No. 2015-02, Consolidation – AmendmentsIn 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.

We are currently evaluating certain contracts along with our tariff revenue, capacity agreements with PJM and wholesale agreements with PJM. We expect additional contracts to be executed during 2017 that will require assessment under the new standard. Through this assessment, we have identified certain key issues that we are continuing to evaluate in order to complete our assessment of the full population of contracts and be able to assess the overall impact to the Consolidation Analysis (Topic 810)
In February 2015,financial statements. These issues include: the application of the practical expedient for measuring progress toward satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services, and how to measure progress toward completion for a performance obligation that is a bundle. We are continuing to work with various non-authoritative industry groups, and monitoring the FASB issued ASU 2015-02,and Transition Resource Group (TRG) activity, as we finalize our accounting policy on these and other industry specific interpretative issues which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the Variable Interest Entity (VIE) guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We do not expect this standard to have an impact on our financial statements upon adoption.are expected in 2017.


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Note 2 – Supplemental Financial Information
 December 31, December 31,
$ in millions 2015 2014 2016 2015
Accounts receivable, net        
Unbilled revenue $43.3
 $49.0
 $43.0
 $43.3
Customer receivables 54.1
 68.7
 71.2
 54.1
Amounts due from partners in jointly-owned stations 16.0
 15.2
 12.7
 16.0
Other 6.9
 20.7
 8.9
 6.9
Provisions for uncollectible accounts (0.8) (0.9) (1.2) (0.8)
Total accounts receivable, net $119.5
 $152.7
 $134.6
 $119.5
        
Inventories        
Fuel and limestone $72.2
 $65.3
 $38.8
 $72.2
Plant materials and supplies 33.7
 32.3
 35.3
 33.7
Other 2.1
 1.4
 1.7
 2.1
Total inventories, at average cost $108.0
 $99.0
 $75.8
 $108.0


Accumulated Other Comprehensive Income (Loss)
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2016, 2015 2014 and 20132014 are as follows:
Details about Accumulated Other Comprehensive Income / (Loss) Components Affected line item in the Statements of Operations Years ended December 31, Affected line item in the Statements of Operations Years ended December 31,
$ in millions   2015 2014 2013   2016 2015 2014
Gains and losses on Available-for-sale securities activity (Note 5):Gains and losses on Available-for-sale securities activity (Note 5):      Gains and losses on Available-for-sale securities activity (Note 5):      
 Other income / (deductions) $—
 $0.4
 $2.1
 Other income $—
 $—
 $0.4
 Tax expense —
 (0.2) (0.7) Tax expense —
 —
 (0.2)
 Net of income taxes —
 0.2
 1.4
 Net of income taxes —
 —
 0.2
Gains and losses on cash flow hedges (Note 6):Gains and losses on cash flow hedges (Note 6):      Gains and losses on cash flow hedges (Note 6):      
 Interest expense (1.1) (1.1) (2.1) Interest expense (1.0) (1.1) (1.1)
 Revenue (18.7) 28.4
 2.2
 Revenue (55.3) (18.7) 28.4
 Purchased power 4.4
 (0.4) 5.0
 Purchased power 9.9
 4.4
 (0.4)
 Total before income taxes (15.4) 26.9
 5.1
 Total before income taxes (46.4) (15.4) 26.9
 Tax expense 5.6
 (11.5) (2.5) Tax benefit / (expense) 16.4
 5.6
 (11.5)
 Net of income taxes (9.8) 15.4
 2.6
 Net of income taxes (30.0) (9.8) 15.4
Amortization of defined benefit pension items (Note 9):Amortization of defined benefit pension items (Note 9):      Amortization of defined benefit pension items (Note 9):      
 Reclassification to Other income / (deductions) 5.6
 4.1
 5.7
 Operation and maintenance 7.7
 5.6
 4.1
 Tax benefit (1.9) (1.4) (1.9) Tax expense (1.8) (1.9) (1.4)
 Net of income taxes 3.7
 2.7
 3.8
 Net of income taxes 5.9
 3.7
 2.7
            
Total reclassifications for the period, net of income taxesTotal reclassifications for the period, net of income taxes $(6.1) $18.3
 $7.8
Total reclassifications for the period, net of income taxes $(24.1) $(6.1) $18.3


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The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 20152016 and 20142015 are as follows:
$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance at December 31, 2013 $0.8
 $6.2
 $(33.7) $(26.7)
        
Other comprehensive loss before reclassifications (0.3) (18.8) (14.8) (33.9)
Amounts reclassified from accumulated other comprehensive income 0.2
 15.4
 2.7
 18.3
Net current period other comprehensive loss (0.1) (3.4) (12.1) (15.6)
        
Balance at December 31, 2014 0.7
 2.8
 (45.8) (42.3) $0.7
 $2.8
 $(45.8) $(42.3)
                
Other comprehensive income / (loss) before reclassifications (0.2) 18.2
 1.7
 19.7
 (0.2) 18.2
 1.7
 19.7
Amounts reclassified from accumulated other comprehensive income / (loss) —
 (9.8) 3.7
 (6.1) —
 (9.8) 3.7
 (6.1)
Net current period other comprehensive income / (loss) (0.2) 8.4
 5.4
 13.6
 (0.2) 8.4
 5.4
 13.6
                
Balance at December 31, 2015 $0.5
 $11.2
 $(40.4) $(28.7) 0.5
 11.2
 (40.4) (28.7)
        
Other comprehensive income / (loss) before reclassifications 0.2
 16.1
 (6.0) 10.3
Amounts reclassified from accumulated other comprehensive income / (loss) —
 (30.0) 5.9
 (24.1)
Net current period other comprehensive income / (loss) 0.2
 (13.9) (0.1) (13.8)
        
Balance at December 31, 2016 $0.7
 $(2.7) $(40.5) $(42.5)

Note 3 – Regulatory AssetsMatters

DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L amended the application requesting to collect $145.0 million per year for seven years supporting the alternative described in

the original filing, named the Distribution Modernization Rider. This plan establishes the terms and Liabilitiesconditions for DP&L’s SSO to customers that do not choose a competitive retail electric supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is competitively bid, and seeks recovery of approximately $10.5 million of regulatory assets. The plan also proposes a new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions from DP&L’s energy efficiency programs, and certain environmental liabilities DP&L may incur.
On January 30, 2017, DP&L, in conjunction with nine intervening parties, filed a settlement in the ESP 3 case, which is subject to PUCO approval. DP&L and the intervening parties agreed to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:
The establishment of a five-year Distribution Modernization Rider designed to collect $90.0 million in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure;
The establishment of a Distribution Investment Rider for distribution investments, with one component designed to collect $35.0 million in revenue per year to enable the implementation of smart grid and advanced metering ending after the fifth year of the term of the ESP;
A commitment by us to separate DP&L’s generation assets from its transmission and distribution assets (if approved by FERC);
A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants;
A commitment to develop or procure wind and/or solar energy projects in Ohio; and
Restrictions on DPL making dividend or tax sharing payments, and various other riders and competitive retail market enhancements.

A hearing on the stipulation has been scheduled for March 8, 2017. A final decision by the PUCO is expected at the end of the second quarter or early in the third quarter of 2017. If the PUCO agrees to the proposed settlement, the average residential customer in the DP&L service territory, using 1,000 kWh on DP&L's SSO, can expect a monthly bill increase of $2.39. There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely basis, and if the ESP 3 stipulation is not approved on a timely basis or if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our results of operations, financial condition and cash flows and our ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted.
In connection with any sale or exiting of our generation plants as contemplated by the ESP settlement or otherwise, DPL and DP&L would expect to incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPL and DP&L.

Regulatory assets and liabilities
In accordance with FASC 980, we have recognized total regulatory assets of $194.3$204.0 million and $211.7$194.3 million at December 31, 20152016 and 2014,2015, respectively, and total regulatory liabilities of $151.4$164.1 million and $128.5$151.4 million at December 31, 20152016 and 2014,2015, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.


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The following table presents DP&L’s Regulatory assets and liabilities:
     December 31,     December 31,
$ in millions Type of Recovery Amortization Through 2015 2014 Type of Recovery Amortization Through 2016 2015
Regulatory assets, current:                
Fuel and purchased power recovery costs A 2016 $13.9
 $16.3
 A 2016 $—
 $13.9
Economic development costs A 2016 0.5
 2.1
 A 2017 0.1
 0.5
Deferred storm costs B 2015 —
 22.3
Energy efficiency program A 2016 —
 1.8
Other miscellaneous A 2016 —
 1.7
Total regulatory assets, current     $14.4
 $44.2
     0.1
 14.4
Regulatory assets, non-current:                
Pension benefits B Ongoing $91.6
 $99.6
 B Ongoing 97.6
 91.6
Deferred recoverable income taxes B/C Ongoing 36.4
 43.1
 B/C Ongoing 35.9
 36.4
Unrecovered OVEC charges D Undetermined 21.0
 10.5
Fuel costs B Undetermined 12.7
 —
 B Undetermined 15.4
 12.7
Unrecovered OVEC charges D Undetermined 10.5
 —
Unamortized loss on reacquired debt B Various 9.0
 9.9
 B Various 8.0
 9.0
Smart grid and advanced metering infrastructure costs D Undetermined 7.3
 6.6
 D Undetermined 7.3
 7.3
Rate case costs D Undetermined 6.3
 1.9
Generation separation costs Undetermined 3.9
 1.6
 D Undetermined 5.7
 3.9
Retail settlement system costs D Undetermined 3.1
 3.1
 D Undetermined 3.1
 3.1
Consumer education campaign D Undetermined 3.0
 3.0
 D Undetermined 3.0
 3.0
Rate case costs D Undetermined 1.9
 —
Other miscellaneous D Undetermined 0.5
 0.6
 D Undetermined 0.6
 0.5
Total regulatory assets, non-current     $179.9
 $167.5
     203.9
 179.9
        
Total regulatory assets $194.3
 $211.7
 $204.0
 $194.3
        
Regulatory liabilities, current:                
Competitive bidding $16.1
 $9.1
Energy efficiency program     $9.2
 $—
     14.1
 9.2
Competitive bidding 9.1
 —
Transmission costs 3.7
 2.9
 3.3
 3.7
Reconciliation rider 2.1
 —
 —
 2.1
Other miscellaneous     0.3
 1.5
     0.2
 0.3
Total regulatory liabilities, current     $24.4
 $4.4
     33.7
 24.4
Regulatory liabilities, non-current:                
Estimated costs of removal - regulated property     $121.8
 $119.3
     126.5
 121.8
Postretirement benefits     5.2
 4.8
     3.9
 5.2
Total regulatory liabilities, non-current     $127.0
 $124.1
     130.4
 127.0
        
Total regulatory liabilities $151.4
 $128.5
 $164.1
 $151.4

A – Recovery of incurred costs without aplus rate of return.
B – Recovery of incurred costs pluswithout a rate of return.
C – Balance has an offsetting liability resulting in no effect on rate base.
D – Recovery not yet determined, but is probable of occurring in future rate proceedings.

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Regulatory assets

Fuel and purchased power recovery costsrepresent 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 recoveryThis rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. As part of the PUCO approval process, an outside auditor reviews fuel costswas discontinued in 2016 and the fuel procurement process. The audit for 2014 is in process. The costs recovered throughremaining balance was transferred to the fuel rider have decreased significantly over the past three years as more SSO supply is provided through the competitive bid. While no further fuel or purchased power costs will be recoverable through the rider, it will continue for up to six months to allow for recovery of the ending deferral amount.Competitive Bid True-up rider.

Fuel costs - long-termlong term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.


Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs.

Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. All such costs have now been recovered.

Energy efficiency program costsrepresent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2014 and 2015, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million per year, after income taxes.

Pension benefitsrepresent 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.

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.

Unrecovered OVEC charges representincludes the portion of capacity charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. Because the fuel rider was discontinued in 2016, all OVEC costs, net of OVEC revenues received through PJM, are now deferred into this asset. DP&L expects to recover these costs through a future rate proceeding.

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

Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the 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,

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file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.

Generation separation costsrepresent financing, redemption and other costs related to the divestiture of DP&L’sgeneration assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&Lrequested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending Distribution Rate Casedistribution rate case filing.

Retail settlement system costsrepresent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Consumer education campaignrepresents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.

Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.

Regulatory liabilities

Energy efficiency program costs see “Regulatory Assets - Energy efficiency program costs” above.

Competitive bidding represents costs associated with the development and implementation of a Competitive Bidding Process,competitive bidding process, establishing contracts to supply power for a portion of DP&L’sStandard Service Offer SSO load, as well as the net over/under recovery of the cost of the power purchased from the bid winners.

Energy efficiency program costs represent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to

recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached.On December 13, 2016 DP&L filed its Energy Efficiency portfolio case with the PUCO that specifies, among other things, that DP&L can collect lost distribution revenues for 2016 and going forward through the EER. The amount of lost revenues earned and accrued in 2016 is $20.1 million. Based on multiple parties’ agreement and past PUCO precedent on the treatment of lost distribution revenues for other utilities, it is probable, but not certain, DP&L will recover this amount. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2015 and 2016, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million after income taxes.

Transmission 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.

Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers.

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.


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Note 4 – Property, Plant and Equipment

The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 20152016 and 2014:2015:
 December 31, December 31,
$ in millions 2015 Composite Rate 2014 Composite Rate 2016 Composite Rate 2015 Composite Rate
Regulated:                
Transmission $413.7
 2.3% $402.4
 2.3% $421.1
 2.3% $413.7
 2.3%
Distribution 1,639.7
 3.3% 1,568.0
 3.5% 1,693.5
 3.2% 1,639.7
 3.3%
General 96.9
 8.4% 116.1
 6.7% 31.6
 3.2% 31.6
 3.2%
Non-depreciable 62.5
 N/A 61.6
 N/A 63.5
 N/A 62.5
 N/A
Total regulated 2,212.8
   2,148.1
   2,209.7
   2,147.5
  
Unregulated:                
Production / Generation 3,016.8
 2.1% 2,957.7
 2.4% 173.9
 26.2% 3,009.8
 2.1%
Non-depreciable 15.1
 N/A 14.9
 N/A 15.0
 N/A 15.0
 N/A
Total unregulated 3,031.9
   2,972.6
   188.9
   3,024.8
  
          
Total property, plant and equipment in service $5,244.7
 2.6% $5,120.7
 2.8% $2,398.6
 4.6% $5,172.3
 2.5%

DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2015,2016, DP&L had $39.0$41.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the

Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

Coal-fired facilities
DP&L’s undivided ownership interest in such facilities at December 31, 2015,2016, is as follows:
 
DP&L Share
 
DP&L Carrying Value
 
DP&L Share
 
DP&L Carrying Value
 
Ownership
%
 
Summer Production Capacity
(MW)
 
Gross Plant
In Service
($ in millions)
 
Accumulated
Depreciation
($ in millions)
 
Construction
Work in
Process
($ in millions)
 
Ownership
%
 
Summer Production Capacity
(MW)
 
Gross Plant
In Service
($ in millions)
 
Accumulated
Depreciation
($ in millions)
 
Construction
Work in
Process
($ in millions)
Jointly-owned production units                    
Conesville - Unit 4 16.5 129
 $27
 $8
 $1
 16.5 129
 $—
 $—
 $—
Killen - Unit 2 67.0 402
 655
 326
 2
 67.0 402
 34
 —
 2
Miami Fort - Units 7 and 8 36.0 368
 366
 171
 6
 36.0 368
 27
 —
 7
Stuart - Units 1 through 4 35.0 808
 772
 338
 18
 35.0 808
 24
 —
 23
Zimmer - Unit 1 28.1 371
 1,104
 690
 12
 28.1 371
 7
 —
 9
Transmission (at varying percentages)     99
 64
 —
     99
 66
 —
Total   2,078
 $3,023
 $1,597
 $39
   2,078
 $191
 $66
 $41

Each of the above generating units has SCR and FGD equipment installed.

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BeckjordOn January 10, 2017, a high pressure feedwater heater shell failed on Unit 6 was retired effective October 1 2014 and DP&L sold its interest in East Bend on December 30, 2014.at the J.M. Stuart station. As the damage assessment process is currently ongoing, we cannot determine the impact to operations or capacity at this time.

As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a fair market value different than DP&L’s carrying value. Since DP&L did not apply push down accounting, this valuation did not affect the carrying value of these stations’ valuation at DP&L. In the fourth quarter of 2013,During 2016, DP&L performed an impairment review of its stations and recorded impairment expense of $86.0$1,353.5 million related to twocertain of its stations, including Conesville and East Bend.Hutchings peaking facilities. See Note 1314 – Fixed-asset Impairment for more information on these impairments.

AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.


Changes in the Liability for Generation AROs
$ in millions  
Balance at December 31, 2013$19.9
Calendar 2014 
Additions3.6
Accretion expense1.1
Settlements(1.7)
Balance at December 31, 201422.9
$22.9
Calendar 2015  
Additions40.3
40.3
Accretion expense2.1
2.1
Settlements(3.2)(3.2)
Balance at December 31, 2015$62.1
62.1
Calendar 2016 
Additions70.2
Accretion expense2.9
Settlements—
Balance at December 31, 2016$135.2

See Note 5 – Fair Value for further discussion on current year ARO additions.

Asset Removal Costs
We continue to record costcosts of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $121.8$126.5 million and $119.3$121.8 million in estimated costs of removal at December 31, 20152016 and 2014,2015, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Assets and LiabilitiesMatters for additional information.


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Changes in the Liability for Transmission and Distribution Asset Removal Costs
$ in millions  
Balance at December 31, 2013$115.0
Calendar 2014 
Additions19.6
Settlements(15.3)
Balance at December 31, 2014119.3
$119.3
Calendar 2015  
Additions24.3
24.3
Settlements(21.8)(21.8)
Balance at December 31, 2015$121.8
121.8
Calendar 2016 
Additions11.7
Settlements(7.0)
Balance at December 31, 2016$126.5


Note 5 – Fair Value

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 fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.


The table below presents the fair value and cost of our non-derivative instruments at December 31, 20152016 and 2014.2015. See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
 December 31, 2015 December 31, 2014 December 31, 2016 December 31, 2015
$ in millions Carrying Value Fair Value Carrying Value Fair Value Cost Fair Value Cost Fair Value
Assets                
Money market funds $0.2
 $0.2
 $0.1
 $0.1
 $0.4
 $0.4
 $0.2
 $0.2
Equity securities 3.0
 3.8
 2.7
 3.7
 2.4
 3.4
 3.0
 3.8
Debt securities 4.4
 4.3
 4.7
 4.7
 4.4
 4.4
 4.4
 4.3
Hedge Funds 0.4
 0.4
 0.8
 0.8
Real Estate 0.3
 0.3
 0.4
 0.4
Hedge funds —
 0.1
 0.4
 0.4
Real estate 0.3
 0.3
 0.3
 0.3
Tangible assets 0.1
 0.1
 —
 —
Total assets $8.3
 $9.0
 $8.7
 $9.7
 $7.6
 $8.7
 $8.3
 $9.0
        
         Carrying Value Fair Value Carrying Value Fair Value
Liabilities                
Debt $762.9
 $764.2
 $877.1
 $882.5
 $749.4
 $763.5
 $756.7
 $764.2

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(unadjusted 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); andor
Level 3 (unobservable inputs)inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability).

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.


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We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 20152016 and 2014.2015.

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 as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 20162020 to 2061.

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

DP&L had $0.8$1.1 million ($0.50.7 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 20152016 and $1.1$0.8 million ($0.70.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.2015.

Various
During the year ended December 31, 2016, $2.6 million ($1.7 million after tax) of various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, an immaterial amount of unrealized gains were reversed into earnings. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.


The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows:
92
Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair Value at December 31, 2016 (a) 
Based on
Quoted Prices
in
Active Markets
 
Other
observable
inputs
 Unobservable inputs
Assets        
Master trust assets        
Money market funds $0.4
 $0.4
 $—
 $—
Equity securities 3.4
 —
 3.4
 —
Debt securities 4.4
 —
 4.4
 —
Hedge funds 0.1
 —
 0.1
 —
Real estate 0.3
 —
 0.3
 —
Tangible assets 0.1
 —
 0.1
 —
Total Master trust assets 8.7
 0.4
 8.3
 —
         
Derivative assets        
FTRs 0.1
 —
 —
 0.1
Interest rate hedge 1.2
 —
 1.2
 —
Forward power contracts 19.5
 —
 19.5
 —
Total derivative assets 20.8
 —
 20.7
 0.1
         
Total assets $29.5
 $0.4
 $29.0
 $0.1
Liabilities        
FTRs $—
 $—
 $—
 $—
Interest rate hedge 0.7
 —
 0.7
 —
Forward power contracts 28.5
 —
 26.0
 2.5
Total derivative liabilities 29.2
 —
 26.7
 2.5
         
Long-term debt 763.5
 —
 745.5
 18.0
         
Total liabilities $792.7
 $—
 $772.2
 $20.5
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(a)Includes credit valuation adjustment.


The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DP&L was determined as follows:
Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair Value at December 31, 2015 (a) 
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 3.8
 —
 3.8
 —
Debt securities 4.3
 —
 4.3
 —
Hedge Funds 0.4
 —
 0.4
 —
Real Estate 0.3
 —
 0.3
 —
Total Master trust assets 9.0
 0.2
 8.8
 —
         
Derivative assets        
FTRs 0.2
 —
 —
 0.2
Forward power contracts 30.6
 —
 30.6
 —
Total derivative assets 30.8
 —
 30.6
 0.2
         
Total assets $39.8
 $0.2
 $39.4
 $0.2
Liabilities        
FTRs $0.5
 $—
 $—
 $0.5
Forward power contracts 27.0
 —
 23.9
 3.1
Total derivative liabilities 27.5
 —
 23.9
 3.6
         
Long-term debt 764.2
 —
 746.1
 18.1
         
Total liabilities $791.7
 $—
 $770.0
 $21.7

(a)Includes credit valuation adjustment.

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The fair value of assets and liabilities at December 31, 2014 and the respective category within the fair value hierarchy for DP&L was determined as follows:
Assets and Liabilities at Fair Value
   Level 1 Level 2 Level 3   Level 1 Level 2 Level 3
$ in millions Fair Value at December 31, 2014 (a) 
Based on
Quoted Prices
in
Active Markets
 
Other
observable
inputs
 Unobservable inputs Fair Value at December 31, 2015 (a) 
Based on
Quoted Prices
in
Active Markets
 
Other
observable
inputs
 Unobservable inputs
Assets                
Master trust assets                
Money market funds $0.1
 $0.1
 $—
 $—
 $0.2
 $0.2
 $—
 $—
Equity securities 3.7
 3.7
 —
 —
 3.8
 —
 3.8
 —
Debt securities 4.7
 4.7
 —
 —
 4.3
 —
 4.3
 —
Hedge Funds 0.8
 —
 0.8
 —
Real Estate 0.4
 0.4
 —
 —
Hedge funds 0.4
 —
 0.4
 —
Real estate 0.3
 —
 0.3
 —
Total Master trust assets 9.7
 8.9
 0.8
 —
 9.0
 0.2
 8.8
 —
                
Derivative assets                
FTRs 0.2
 —
 —
 0.2
Forward power contracts 15.1
 —
 13.9
 1.2
 30.6
 —
 30.6
 —
Total derivative assets 15.1
 —
 13.9
 1.2
 30.8
 —
 30.6
 0.2
                
Total assets $24.8
 $8.9
 $14.7
 $1.2
 $39.8
 $0.2
 $39.4
 $0.2
Liabilities                
FTRs $0.5
 $—
 $—
 $0.5
Forward power contracts $11.2
 $—
 $11.2
 $—
 27.0
 —
 23.9
 3.1
FTRS 0.6
 —
 —
 0.6
Heating Oil Futures 0.4
 0.4
 —
 —
Natural Gas Futures 0.1
 0.1
 —
 —
Total derivative liabilities 12.3
 0.5
 11.2
 0.6
 27.5
 —
 23.9
 3.6
                
Long-term debt 882.5
 —
 864.3
 18.2
 764.2
 —
 746.1
 18.1
                
Total liabilities $894.8
 $0.5
 $875.5
 $18.8
 $791.7
 $—
 $770.0
 $21.7

(a)Includes credit valuation adjustment.

Our financial instruments are valued using the market approach in the following categories:
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 (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.
Level 3 inputs, such as 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.


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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. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.

Approximately 99%94.7% 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. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $73.1 million ($47.5 million after tax) and $39.2 million ($25.5 million after tax) during the years ended December 31, 2016 and $3.02015, respectively. Increases to the AROs for the Stuart and Killen Plants totaling $67.9 million ($2.044.1 million after tax) duringwere recorded in 2016 to reflect revised estimated closure expenditures as well as plant closure dates that are earlier than previously forecast. Smaller changes were also recorded to the 12 months ended December 31, 2015 and 2014, respectively.AROs for certain other plants to reflect changes in estimated closure costs. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ($26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 – Property, Plant and Equipment for more information about AROs.

When evaluating impairment of long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount.

The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
$ in millions Year ended December 31, 2013
  Carrying Fair Value Gross
  Amount Level 1 Level 2 Level 3 Loss
Assets          
Long-lived assets held and used (a)
          
Conesville $30.0
 $—
 $—
 $20.0
 $10.0
East Bend $76.0
 $—
 $—
 $—
 $76.0
  Measurement Carrying Fair Value Gross
$ in millions Date Amount Level 1 Level 2 Level 3 Loss
Long-lived assets (a)
            
    Year ended December 31, 2016
Killen December 31, 2016 $118.1
 $—
 $—
 $42.8
 $75.3
Stuart December 31, 2016 $207.3
 $—
 $—
 $57.4
 149.9
Miami Fort December 31, 2016 $194.2
 $—
 $—
 $36.5
 157.7
Zimmer December 31, 2016 $115.0
 $—
 $—
 $23.7
 91.3
Conesville December 31, 2016 $21.9
 $—
 $—
 $1.1
 20.8
Hutchings peaking facilities December 31, 2016 $3.0
 $—
 $—
 $1.6
 1.4
Stuart June 30, 2016 $456.4
 $—
 $—
 $164.4
 292.0
Killen June 30, 2016 $330.5
 $—
 $—
 $84.3
 246.2
Zimmer June 30, 2016 $429.9
 $—
 $—
 $111.0
 318.9
             
Total impairment loss           $1,353.5

(a)See Note 1314 – Fixed-asset Impairment for further information.

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assetson a non-recurring basis during the year ended December 31, 2013:2016:
$ in millionsFair ValueValuation TechniqueUnobservable inputRange (Weighted Average)
Long-lived assets held and used:
DP&L (Conesville)
$—
Discounted cash flowsAnnual revenue growth-31% to 18% (0)
$ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average)
Long-lived assets held and used:
    Year ended December 31, 2016
Killen December 31, 2016 $42.8
 Discounted cash flow Annual revenue growth -14.2% to 2.9% (-8.0%)
        Annual pre-tax operating margin -56.6% to 42.4% (-15.5%)
        Weighted-average cost of capital 10.0%
           

$ in millions Measurement date Fair value Valuation technique Unobservable input Range (weighted average)
Long-lived assets held and used:
    Year ended December 31, 2016
Stuart December 31, 2016 $57.4
 Discounted cash flow Annual revenue growth -11.9% to 1.1% (-4.7%)
        Annual pre-tax operating margin -61.4% to 75.1% (8.0%)
    ��   Weighted-average cost of capital 10.0%
           
Miami Fort December 31, 2016 $36.5
 Market value Indicative offer price  
           
Zimmer December 31, 2016 $23.7
 Market value Indicative offer price  
           
Conesville December 31, 2016 $1.1
 Discounted cash flow Annual revenue growth -19.3% to 10.9% (0.6%)
        Annual pre-tax operating margin -54.3% to 99.4% (20.2%)
        Weighted-average cost of capital N/A
           
Hutchings peaking facilities December 31, 2016 $1.6
 Discounted cash flow Annual revenue growth -19.5% to 25.9% (-0.7%)
        Annual pre-tax operating margin -40.3% to 63.1% (12.1%)
        Weighted-average cost of capital 7.0%
           
Stuart June 30, 2016 $164.4
 Discounted cash flow Annual revenue growth -9.0% to 10.0% (2.0%)
        Annual pre-tax operating margin -29.0% to 52.0% (5.0%)
        Weighted-average cost of capital 9.0%
           
Killen June 30, 2016 $84.3
 Discounted cash flow Annual revenue growth -11.0% to 13.0% (2.0%)
        Annual pre-tax operating margin -50.0% to 67.0% (6.0%)
        Weighted-average cost of capital 11.0%
           
Zimmer June 30, 2016 $111.0
 Discounted cash flow Annual revenue growth -14.0% to 13.0% (1.0%)
        Annual pre-tax operating margin -46.0% to 80.0% (4.0%)
        Weighted-average cost of capital 9.0%


Note 6 – 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 if they qualify under FASC 815 for accounting purposes.


At December 31, 2016, DP&L had the following outstanding derivative instruments:
95
Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 2.3
 —
 2.3
Natural Gas Not designated Dths 1,590.0
 —
 1,590.0
Forward Power Contracts Designated MWh 342.9
 (9,974.5) (9,631.6)
Forward Power Contracts Not designated MWh 2,568.3
 (2,037.5) 530.8
Interest Rate Swaps Designated USD 200,000.0
 —
 200,000.0
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At December 31, 2015, DP&L had the following outstanding derivative instruments:
Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 10.2
 —
 10.2
Forward Power Contracts Designated MWh 1,676.7
 (7,795.8) (6,119.1)
Forward Power Contracts Not designated MWh 5,049.9
 (1,665.7) 3,384.2

At December 31, 2014, DP&L had the following outstanding derivative instruments:
Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 10.5
 —
 10.5
Heating Oil Futures Not designated Gallons 378.0
 —
 378.0
Natural Gas Not designated Dths 200.0
   200.0
Forward Power Contracts Designated MWh 175.0
 (2,991.0) (2,816.0)
Forward Power Contracts Not designated MWh 1,725.2
 (2,804.0) (1,078.8)

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

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


96
TableIn November 2016, we entered into two interest rate swaps to hedge the variable interest on our $200.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of Contents$200.0 million and will settle monthly based on a one month LIBOR. We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.


The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:
 Years ended December 31, Years ended December 31,
 2015 2015 2014 2014 2013 2013 2016 2015 2014
$ in millions (net of tax) Power 
Interest Rate
Hedge
 Power 
Interest Rate
Hedge
 Power 
Interest Rate
Hedge
 Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
 Power 
Interest Rate
Hedges
Beginning accumulated derivative gain / (loss) in AOCI $0.2
 $2.6
 $1.0
 $5.2
 $(4.7) $7.3
Beginning accumulated derivative gain in AOCI $9.2
 $2.0
 $0.2
 $2.6
 $1.0
 $5.2
                        
Net gains / (losses) associated with current period hedging transactions 18.2
 —
 (18.8) —
 1.0
 —
 15.7
 0.4
 18.2
 —
 (18.8) —
Net gains / (losses) reclassified to earnings:                        
Interest Expense —
 (0.6) —
 (2.6) —
 (2.1) —
 (0.8) —
 (0.6) —
 (2.6)
Revenues (12.0) —
 18.2
 —
 1.4
 —
 (35.6) —
 (12.0) —
 18.2
 —
Purchased Power 2.8
 —
 (0.2) —
 3.3
 —
 6.4
 —
 2.8
 —
 (0.2) —
Ending accumulated derivative gain in AOCI $9.2
 $2.0
 $0.2
 $2.6
 $1.0
 $5.2
Ending accumulated derivative gain / (loss) in AOCI $(4.3) $1.6
 $9.2
 $2.0
 $0.2
 $2.6
                        
Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.
                        
Portion expected to be reclassified to earnings in the next twelve months (a)
 $5.9
 $(0.6)         $(3.5) $(0.8)        
                        
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 36
 —
         15
 44
        

(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.

Derivatives not designated as hedges
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 consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oilnatural gas futures and certain forward power contracts.

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

Regulatory assets and liabilities
In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a

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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 are deferred as a regulatory asset or liability until the contracts settle. If these unrealized

gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.

The following tables show the amount and classification within the statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the years ended December 31, 2016, 2015 2014 and 2013.2014.
 Year ended December 31, 2015 Year ended December 31, 2016
$ in millions Heating Oil FTRs Power Natural Gas Total Heating Oil FTRs Power Natural Gas Total
Derivatives not designated as hedging instruments
Change in unrealized loss $0.4
 $0.3
 $(6.3) $0.1
 $(5.5)
Change in unrealized gain / (loss) $—
 $0.3
 $3.9
 $—
 $4.2
Realized gain / (loss) (0.3) (0.2) (9.9) (0.1) (10.5) —
 (0.6) (7.9) 2.6
 (5.9)
Total $0.1
 $0.1
 $(16.2) $—
 $(16.0) $—
 $(0.3) $(4.0) $2.6
 $(1.7)
Recorded on Balance Sheet:                    
Regulatory asset $0.1
 $—
 $—
 $—
 $0.1
 $—
 $—
 $—
 $—
 $—
Recorded in Income Statement: gain / (loss)        
Recorded in Statement of Operations: gain / (loss)Recorded in Statement of Operations: gain / (loss)        
Revenue —
 —
 27.4
 —
 27.4
 —
 —
 (18.1) —
 (18.1)
Purchased Power —
 0.1
 (43.6) —
 (43.5) —
 (0.3) 14.1
 2.6
 16.4
Fuel —
 —
 —
 —
 —
          
Total $0.1
 $0.1
 $(16.2) $—
 $(16.0) $—
 $(0.3) $(4.0) $2.6
 $(1.7)

 Year ended December 31, 2014 Year ended December 31, 2015
$ in millions Heating Oil FTRs Power Natural Gas Total Heating Oil FTRs Power Natural Gas Total
Derivatives not designated as hedging instruments          Derivatives not designated as hedging instruments
Change in unrealized gain / (loss) $(0.6) $(0.8) $(1.5) $(0.1) $(3.0) $0.4
 $0.3
 $(6.3) $0.1
 $(5.5)
Realized gain / (loss) (0.1) 0.7
 (3.0) (0.1) (2.5) (0.3) (0.2) (9.9) (0.1) (10.5)
Total $(0.7) $(0.1) $(4.5) $(0.2) $(5.5) $0.1
 $0.1
 $(16.2) $—
 $(16.0)
Recorded on Balance Sheet:                    
Regulatory asset $(0.1) $—
 $—
 $—
 $(0.1) $0.1
 $—
 $—
 $—
 $0.1
Recorded in Income Statement: gain / (loss)        
Recorded in Statement of Operations: gain / (loss)Recorded in Statement of Operations: gain / (loss)        
Revenue $—
 $—
 $0.7
 $—
 $0.7
 —
 —
 27.4
 —
 27.4
Purchased Power —
 (0.1) (5.2) (0.2) (5.5) —
 0.1
 (43.6) —
 (43.5)
Fuel (0.6) —
 —
 —
 (0.6)
          
Total $(0.7) $(0.1) $(4.5) $(0.2) $(5.5) $0.1
 $0.1
 $(16.2) $—
 $(16.0)


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 Year ended December 31, 2013 Year ended December 31, 2014
$ in millions 
NYMEX
Coal
 Heating Oil FTRs Power Total Heating Oil FTRs Power Natural Gas Total
Derivatives not designated as hedging instrumentsDerivatives not designated as hedging instruments        Derivatives not designated as hedging instruments        
Change in unrealized gain / (loss) $—
 $—
 $0.3
 $(1.2) $(0.9)
Change in unrealized loss $(0.6) $(0.8) $(1.5) $(0.1) $(3.0)
Realized gain / (loss) —
 0.1
 1.2
 1.6
 2.9
 (0.1) 0.7
 (3.0) (0.1) (2.5)
Total $—
 $0.1
 $1.5
 $0.4
 $2.0
 $(0.7) $(0.1) $(4.5) $(0.2) $(5.5)
Recorded on Balance Sheet:                    
Partners' share of gain $—
 $—
 $—
 $—
 $—
Regulatory (asset) / liability —
 —
 —
 —
 —
 $(0.1) $—
 $—
 $—
 $(0.1)
          
Recorded in Income Statement: gain / (loss)        
Recorded in Statement of Operations: gain / (loss)Recorded in Statement of Operations: gain / (loss)        
Revenue —
 —
 —
 0.2
 0.2
 —
 —
 0.7
 —
 0.7
Fuel (0.6) —
 —
 —
 (0.6)
Purchased Power —
 —
 1.5
 0.2
 1.7
 —
 (0.1) (5.2) (0.2) (5.5)
Fuel —
 0.1
 —
 —
 0.1
O&M —
 —
 —
 —
 —
Total $—
 $0.1
 $1.5
 $0.4
 $2.0
 $(0.7) $(0.1) $(4.5) $(0.2) $(5.5)


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The following tables show the fair value, balance sheet classification and hedging designation of DP&L’s derivative instruments at December 31, 20152016 and 2014.2015.
Fair Values of Derivative Instruments
December 31, 2015
December 31, 2016December 31, 2016
     Gross Amounts Not Offset in the Balance Sheets       Gross Amounts Not Offset in the Balance Sheets  
$ in millions Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount
Assets                    
Short-term derivative positions (presented in Other current assets)Short-term derivative positions (presented in Other current assets)      Short-term derivative positions (presented in Other current assets)      
Forward power contracts Designated $16.2
 $(7.1) $—
 $9.1
 Designated $11.0
 $(10.5) $—
 $0.5
Forward power contracts Not designated 7.4
 (5.5) —
 1.9
 Not designated 6.0
 (4.7) —
 1.3
FTRs 0.2
 (0.2) —
 —
 Not designated 0.1
 —
 —
 0.1
Long-term derivative positions (presented in Other deferred assets)Long-term derivative positions (presented in Other deferred assets)  
  
  
Long-term derivative positions (presented in Other deferred assets)  
  
  
Forward power contracts Designated 3.0
 (2.4) —
 0.6
 Designated 0.6
 (0.6) —
 —
Interest Rate Swaps Designated 1.2
 —
 —
 1.2
Forward power contracts Not designated 4.0
 (2.7) —
 1.3
 Not designated 1.9
 (1.0) —
 0.9
Total assets   $30.8
 $(17.9) $—
 $12.9
   $20.8
 $(16.8) $—
 $4.0
        
Liabilities                    
Short-term derivative positions (presented in Other current liabilities)Short-term derivative positions (presented in Other current liabilities)    Short-term derivative positions (presented in Other current liabilities)    
Forward power contracts Designated $7.1
 $(7.1) $—
 $—
 Designated $16.4
 $(10.5) $(5.5) $0.4
Interest Rate Swaps Designated 0.7
 —
 —
 0.7
Forward power contracts Not designated 14.5
 (5.5) (8.0) 1.0
 Not designated 7.7
 (4.7) —
 3.0
FTRs Not designated 0.5
 (0.2) —
 0.3
 Not designated —
 —
 —
 —
Long-term derivative positions (presented in Other deferred liabilities)Long-term derivative positions (presented in Other deferred liabilities)  
  
Long-term derivative positions (presented in Other deferred liabilities)  
  
Forward power contracts Designated 2.7
 (2.4) —
 0.3
 Designated 2.4
 (0.6) (0.8) 1.0
Forward power contracts Not designated 2.7
 (2.7) —
 —
 Not designated 2.0
 (1.0) —
 1.0
Total liabilities   $27.5
 $(17.9) $(8.0) $1.6
   $29.2
 $(16.8) $(6.3) $6.1

(a)Includes credit valuation adjustment.

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Fair Values of Derivative Instruments
December 31, 2014
December 31, 2015December 31, 2015
     Gross Amounts Not Offset in the Balance Sheets       Gross Amounts Not Offset in the Balance Sheets  
$ in millions Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount Hedging Designation Gross Fair Value as presented in the Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Amount
Assets                    
Short-term derivative positions (presented in Other current assets)Short-term derivative positions (presented in Other current assets)      Short-term derivative positions (presented in Other current assets)      
Forward power contracts Designated $5.6
 $(2.0) $—
 $3.6
 Designated $16.2
 $(7.1) $—
 $9.1
Forward power contracts Not designated 5.6
 (3.4) —
 2.2
 Not designated 7.4
 (5.5) —
 1.9
FTRs Not designated —
 —
 —
 —
 Not designated 0.2
 (0.2) —
 —
Heating oil futures Not designated —
 —
 —
 —
Long-term derivative positions (presented in Other deferred assets)Long-term derivative positions (presented in Other deferred assets)  
  
  
Long-term derivative positions (presented in Other deferred assets)  
  
  
Forward power contracts Designated 0.3
 (0.3) —
 —
 Designated 3.0
 (2.4) —
 0.6
Forward power contracts Not designated 3.6
 (0.9) —
 2.7
 Not designated 4.0
 (2.7) —
 1.3
Total assets   $15.1
 $(6.6) $—
 $8.5
   $30.8
 $(17.9) $—
 $12.9
        
Liabilities                    
Short-term derivative positions (presented in Other current liabilities)Short-term derivative positions (presented in Other current liabilities)    Short-term derivative positions (presented in Other current liabilities)    
Forward power contracts Designated $2.1
 $(2.0) $—
 0.1
 Designated $7.1
 $(7.1) $—
 $—
Forward power contracts Not designated 7.5
 (3.4) (4.1) —
 Not designated 14.5
 (5.5) (8.0) 1.0
FTRs Not designated 0.6
 —
 —
 0.6
 Not designated 0.5
 (0.2) —
 0.3
Heating oil futures Not designated 0.4
 —
 (0.4) —
Natural gas futures Not designated 0.1
 —
 (0.1) —
Long-term derivative positions (presented in Other deferred liabilities)Long-term derivative positions (presented in Other deferred liabilities)  
  
Long-term derivative positions (presented in Other deferred liabilities)  
  
Forward power contracts Designated 0.6
 (0.3) (0.3) —
 Designated 2.7
 (2.4) —
 0.3
Forward power contracts Not designated 1.0
 (0.9) —
 0.1
 Not designated 2.7
 (2.7) —
 —
Total liabilities   $12.3
 $(6.6) $(4.9) $0.8
   $27.5
 $(17.9) $(8.0) $1.6

(a)Includes credit valuation adjustment.

Credit risk-related contingent features
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. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss.


The aggregate fair value of DP&L’s derivative instruments that are in a MTM loss position at December 31, 20152016 is $27.5$29.2 million. This amount is offset by $8.0$6.3 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

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the asset position of counterparties with master netting agreements of $17.9$16.8 million. If DP&L debt were to fall below investment grade, DP&L could be required to post collateral for the remaining $1.6$6.1 million.


Note 7 – Debt

Long-term debt is as follows:
Long-term debt        
$ in millions Interest Rate Maturity December 31, 2015 December 31, 2014 Interest Rate Maturity December 31, 2016 December 31, 2015
First mortgage bonds 1.875% 2016 $445.0
 $445.0
Pollution control series 4.7% 2028 —
 35.3
Pollution control series 4.8% 2034 —
 179.1
Pollution control series 4.8% 2036 100.0
 100.0
Pollution control series - rates from: 0.02% - 0.12% and 0.04% - 0.15% (a) 2040 —
 100.0
Pollution control series - rates from: 1.13% - 1.17% 2020 200.0
 —
Term loan - rates from: 4.00% - 4.01% (a) 2022 $445.0
 $—
First Mortgage Bonds 1.875% 
 —
 445.0
Tax-exempt First Mortgage Bonds 4.8% 2036 100.0
 100.0
Tax-exempt First Mortgage Bonds - rates from: 1.29% - 1.42% (a) and 1.13% - 1.17% (b) 2020 200.0
 200.0
U.S. Government note 4.2% 2061 18.1
 18.2
 4.2% 2061 18.0
 18.1
Capital leases 
 
 0.4
 —
Unamortized deferred financing costs (11.8) (6.2)
Unamortized debt discount (0.2) (0.5) (2.2) (0.2)
Subtotal 762.9
 877.1
 749.4
 756.7
Less: current portion (444.9) (0.1) (4.7) (443.1)
Total $318.0
 $877.0
 $744.7
 $313.6

(a)Range of interest rates for the year ended December 31, 2016.
(b)Range of interest rates for the year ended December 31, 2015.

At December 31, 2015,2016, maturities of long-term debt are summarized as follows:
Due within the twelve months ending December 31, 
Due during the years ending December 31, 
$ in millions  
2016$445.1
20170.1
$4.7
20180.1
4.6
20190.2
4.6
2020200.2
204.6
20214.5
Thereafter117.4
540.0
763.1
763.0
Unamortized discount(0.2)
Unamortized discounts and premiums, net(2.2)
Total long-term debt$762.9
$760.8

Significant transactions
On December 31, 2016, DP&L borrowed $5.0 million from DPL at an interest rate of 3.02%. The notes were due on or before January 30, 2017 and were repaid on the maturity date.

On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly, and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.

On December 31, 2015, DP&L borrowed $35.0 million from DPL at an interest rate of 2.67%. The notes were due on or before December 31, 2016 and were repaid on January 29, 2016.

On July 1, 2015, the $35.3 million of DP&L's 4.7% pollution control bondstax-exempt First Mortgage Bonds due January 2028 and $41.3 million of DP&L's 4.8% pollution control bondstax-exempt First Mortgage Bonds due January of 2034 were called at par and were redeemed with cash.

On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by

an additional $100.0 million and a maturity date of July 2020. At December 31, 2015,2016, there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 20152016 or 2014.2015. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.


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On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bondstax-exempt First Mortgage Bonds due November 2040, terminated the amended standby letter of credit facilities that supported these pollution control bonds,tax-exempt First Mortgage Bonds, and called $137.8 million of 4.8% pollution control bondstax-exempt First Mortgage Bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with a new variable interest rate pollution control bondstax-exempt Term Loan secured by first mortgage bondsFirst Mortgage Bonds in an equivalent amount. In connection with the sale of the new pollution control bonds,tax-exempt First Mortgage Bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L.On November 21, 2016, the DP&L $200.0 million variable-rate Term Loan were hedged with floating for fixed rate interest rate swaps, reducing interest rate risk exposure for the term of the bonds.

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

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. Substantially all property, plant and equipment of DP&L is subject to the lien of the First and Refunding Mortgage. Substantially concurrent with this transaction, DP&L redeemed $470.0 million of previously outstanding first mortgage bonds.

Debt covenants and restrictions
In connection with DP&L’s sale of $200.0 million of variable rate pollution control bondstax-exempt First Mortgage Bonds dated August 1, 2015, DP&L entered into an unsecured revolving credit agreement and a Bond Purchase and Covenants Agreement. These agreements contain representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L and have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the new $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that after separation required compliance with this financial covenant shall be suspended (a) any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility or (b) for the time period January 1, 2017 to December 31, 2017 (as modified by the amendment described below) if during such time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt.

On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment DP&L’s Total Debt to Total Capitalization ratio for the period ending December 31, 2016 is 0.53 to 1.00, compared to 0.68 to 1.00 before the amendment. The amendment also changed, for each amendment, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

As of December 31, 2015,2016, DP&L was in compliance with all debt covenants, including the financial covenants described above and did not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.


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Note 8 – Income Taxes

DP&L’s components of income tax expense were as follows:
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Computation of tax expense      
Federal income tax expense (a)
 $49.3
 $53.8
 $35.5
Computation of tax expense / (benefit)      
Federal income tax expense / (benefit) (a)
 $(418.5) $49.3
 $53.8
Increases (decreases) in tax resulting from:            
State income taxes, net of federal effect 0.4
 1.2
 0.3
 (5.0) 0.4
 1.2
Depreciation of AFUDC - Equity (2.8) (2.7) (2.5) 3.3
 (2.8) (2.7)
Investment tax credit amortized (2.4) (2.5) (2.5) (2.3) (2.4) (2.5)
Section 199 - domestic production deduction (6.1) (4.6) (4.1) (5.3) (6.1) (4.6)
Accrual (settlement) for open tax years —
 (6.6) (8.8) 3.4
 —
 (6.6)
Other, net (b)
 (3.3) 1.1
 0.7
 2.0
 (3.3) 1.1
Total tax expense $35.1
 $39.7
 $18.6
Tax expense / (benefit) $(422.4) $35.1
 $39.7
            
Components of Tax Expense      
Components of tax expense / (benefit)      
Federal - current $55.8
 $34.1
 $38.6
 $51.6
 $55.8
 $34.1
State and Local - current 0.8
 0.5
 (0.1) 0.6
 0.8
 0.5
Total current 56.6
 34.6
 38.5
 52.2
 56.6
 34.6
            
Federal - deferred (21.0) 4.1
 (20.4) (466.3) (21.0) 4.1
State and local - deferred (0.5) 1.0
 0.5
 (8.3) (0.5) 1.0
Total deferred (21.5) 5.1
 (19.9) (474.6) (21.5) 5.1
            
Total tax expense $35.1
 $39.7
 $18.6
Tax expense / (benefit) $(422.4) $35.1
 $39.7

(a)The statutory tax rate of 35% was applied to pre-tax earnings.
(b)Includes expense of $2.9 million, expense of $0.4 million and benefit of $0.7 million in the years ended December 31, 2016, 2015 and 2014, respectively, of income tax related to adjustments from prior years.

Effective and Statutory Rate Reconciliation
The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DP&L's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 20152016, 20142015 and 20132014:
 Years ended December 31, Years ended December 31,
 2015 2014 2013 2016 2015 2014
Statutory Federal tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %
State taxes, net of Federal tax benefit 0.3 % 0.8 % 0.3 % 0.4 % 0.3 % 0.8 %
AFUDC - Equity (2.0)% (1.7)% (2.4)% (0.3)% (2.0)% (1.7)%
Amortization of investment tax credits (1.7)% (1.6)% (2.4)% 0.2 % (1.7)% (1.6)%
Section 199 - domestic production deduction (4.3)% (3.0)% (4.0)% 0.4 % (4.3)% (3.0)%
Other - net (2.5)% (3.8)% (8.3)% (0.4)% (2.5)% (3.8)%
Effective tax rate 24.8 % 25.7 % 18.2 % 35.3 % 24.8 % 25.7 %

Deferred Income Taxes
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect

when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

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Components of Deferred Tax Assets and Liabilities
 December 31, December 31,
$ in millions 2015 2014 2016 2015
Net non-current Assets / (Liabilities)        
Depreciation / property basis $(608.8) $(618.8) $(129.8) $(608.8)
Income taxes recoverable (12.0) (14.8) (11.9) (12.0)
Regulatory assets (11.5) (18.0) (9.1) (11.5)
Investment tax credit 7.0
 8.6
 6.3
 7.0
Compensation and employee benefits 3.6
 5.2
 1.1
 3.6
Other (9.5) (12.2) (2.9) (9.5)
Net non-current liabilities $(631.2) $(650.0) $(146.3) $(631.2)
Net current Assets / (Liabilities) (c)
    
Other $—
 $0.5
Net current assets / (liabilities) $—
 $0.5

(a)The statutory tax rate of 35% was applied to pre-tax earnings.
(b)Includes benefit of $0.4 million, expense of $0.7 million and benefit of $1.1 million in the years ended December 31, 2015, 2014 and 2013, respectively, of income tax related to adjustments from prior years.
(c)
Amounts are included within Other prepayments and current assets and Other current liabilities on the Balance Sheets of DP&L.

The following table presents the tax (benefit) / expense related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Tax expense / (benefit) $7.5
 $(6.0) $7.0
 $(7.0) $7.5
 $(6.0)

Uncertain Tax Positions
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows:
 
$ in millions  
Balance at December 31, 2013$8.8
Calendar 2014 
Tax positions taken during prior period2.8
Lapse of Statute of Limitations(8.6)
Settlement with taxing authorities—
Balance at December 31, 20143.0
$3.0
 
Calendar 2015  
Tax positions taken during prior period—
—
Lapse of Statute of Limitations—
—
Balance at December 31, 2015$3.0
3.0
 
Calendar 2016 
Tax positions taken during prior period3.4
Lapse of Statute of Limitations(1.5)
Balance at December 31, 2016$4.9

Of the December 31, 20152016 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.

We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued and expense (benefit) recorded were not material for each period presented.


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Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal – 20102011 and forward
State and Local – 20102011 and forward

None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations.

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 in 2013.

Note 9 – Benefit Plans

Defined contribution plans
DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.

Certain non-union and union employees become eligible to participate in the managementtheir respective plan on the first day of the month following the first full calendar month of employment; provided the employee worked at least 160 hours in that calendar month. Union employees become eligible to participate in the union plan on the first day of the first month following 30 days of employment. Effective January 1, 2016, employees in both plans are eligible to participate upon date of hire.

Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,100$2,200 for 20152016 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions.

For the years ended December 31, 2016, 2015 2014 and 20132014 DP&L's contributions to all defined contribution plans were $4.9 million, $4.8 million $4.7 million and $4.8$4.7 million per year, respectively.

Defined benefit plans
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.

Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.

In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and

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retired key executives. We also include our net liability to our partners in our co-owned generating plants related to our share of their pension costs within Pension, retiree and other benefits on our Balance Sheets.

We recognize an asset for a plan’s overfunded status and 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. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.

Postretirement benefits
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have

funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $15.8 million and $15.0 million at December 31, 2016 and 2015, respectively, were not material to the financial statements in the periods covered by this report.


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The following tables set forth the changes in our pension and postemployment benefit plans’plan's obligations and assets recorded on the balance sheets at December 31, 20152016 and 2014.2015. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presentedaggregate and have not been adjusted for postemployment obligations include both health$1.3 million and life insurance benefits.$2.2 million of costs billed to the service company for the years ended December 31, 2016 and 2015.
$ in millions Pension
  Years ended December 31,
  2015 2014
Change in benefit obligation    
Benefit obligation at beginning of period $443.8
 $370.5
Service cost 7.1
 5.9
Interest cost 17.3
 17.5
Plan amendments —
 6.8
Actuarial (gain) / loss (34.5) 67.3
Benefits paid (22.9) (24.2)
Benefit obligation at end of period 410.8
 443.8
Change in plan assets    
Fair value of plan assets at beginning of period 371.7
 349.1
Actual return on plan assets (8.8) 46.4
Contributions to plan assets 5.4
 0.4
Benefits paid (22.9) (24.2)
Fair value of plan assets at end of period 345.4
 371.7
     
Funded status of plan $(65.4) $(72.1)
     
  December 31,
  2015 2014
Amounts recognized in the Balance sheets    
Current liabilities $(0.4) $(0.4)
Non-current liabilities (65.0) (71.7)
Net liability at Year ended December 31, $(65.4) $(72.1)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax    
Components:    
Prior service cost $17.0
 $20.3
Net actuarial loss / (gain) 139.7
 152.5
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $156.7
 $172.8
Recorded as:    
Regulatory asset $91.1
 $99.0
Regulatory liability —
 —
Accumulated other comprehensive income 65.6
 73.8
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $156.7
 $172.8


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$ in millions Postretirement Pension
 Years ended December 31, Years ended December 31,
 2015 2014 2016 2015
Change in benefit obligation        
Benefit obligation at beginning of period $19.6
 $19.7
Benefit obligation at January 1 $410.8
 $443.8
Service cost 0.2
 0.2
 5.7
 7.1
Interest cost 0.6
 0.8
 14.7
 17.3
Plan curtailment 2.5
 —
Actuarial (gain) / loss (1.1) 0.2
 9.0
 (34.5)
Benefits paid (1.5) (1.3) (23.1) (22.9)
Benefit obligation at end of period 17.8
 19.6
Benefit obligation at December 31 419.6
 410.8
    
Change in plan assets        
Fair value of plan assets at beginning of period 3.3
 3.7
Contributions to plan assets 1.0
 0.9
Fair value of plan assets at January 1 345.4
 371.7
Actual return on plan assets 13.3
 (8.8)
Employer contributions 5.4
 5.4
Benefits paid (1.5) (1.3) (23.1) (22.9)
Fair value of plan assets at end of period 2.8
 3.3
Fair value of plan assets at December 31 341.0
 345.4
        
Funded status of plan $(15.0) $(16.3) $(78.6) $(65.4)
    
 December 31,    
 2015 2014 December 31,
Amounts recognized in the Balance sheets     2016 2015
Current liabilities $(0.4) $(0.5) $(0.4) $(0.4)
Non-current liabilities (14.6) (15.8) (78.2) (65.0)
Net liability at Year ended December 31, $(15.0) $(16.3)
Net liability $(78.6) $(65.4)
Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax        
Components:        
Prior service cost $0.5
 $0.6
 $10.8
 $17.0
Net actuarial loss / (gain) (6.2) (5.8)
Net actuarial loss 150.9
 139.7
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $(5.7) $(5.2) $161.7
 $156.7
Recorded as:        
Regulatory asset $0.3
 $—
 $97.1
 $91.1
Regulatory liability (5.1) (4.5)
Accumulated other comprehensive income (0.9) (0.7) 64.6
 65.6
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax $(5.7) $(5.2) $161.7
 $156.7

The accumulated benefit obligation for our defined benefit pension plans was $401.2$409.2 million and $431.0$401.2 million at December 31, 20152016 and 2014,2015, respectively.


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The net periodic benefit cost of the pension and postretirement plans were:
Net Periodic Benefit Cost - Pension      
  Years ended December 31,
$ in millions 2015 2014 2013
Service cost $7.1
 $5.9
 $7.2
Interest cost 17.3
 17.5
 15.6
Expected return on assets (a)
 (22.6) (22.9) (23.6)
Amortization of unrecognized:      
Actuarial gain 9.8
 6.4
 9.3
Prior service cost 3.3
 2.8
 2.8
Net periodic benefit cost $14.9
 $9.7
 $11.3

Net Periodic Benefit Cost - Postretirement      
Net Periodic Benefit Cost      
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Service cost $0.2
 $0.2
 $0.2
 $5.7
 $7.1
 $5.9
Interest cost 0.6
 0.8
 0.8
 14.7
 17.3
 17.5
Expected return on assets (a)
 (0.1) (0.2) (0.2) (22.8) (22.6) (22.9)
Plan curtailment 5.7
 —
 —
Amortization of unrecognized:            
Actuarial loss (0.6) (0.8) (0.7) 7.2
 9.8
 6.4
Prior service cost 0.1
 0.1
 0.1
 3.0
 3.3
 2.8
Net periodic benefit cost $0.2
 $0.1
 $0.2
 $13.5
 $14.9
 $9.7
      
Rates relevant to each year's expense calculations      
Discount rate 4.49% 4.02% 4.86%
Expected return on plan assets 6.50% 6.50% 6.75%

Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Pension      
  Years ended December 31,
$ in millions 2015 2014 2013
Net actuarial loss / (gain) $(3.0) $43.8
 $(11.7)
Prior service cost —
 6.8
 —
Reversal of amortization item:      
Net actuarial loss (9.8) (6.4) (9.3)
Prior service cost (3.3) (2.8) (2.8)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(16.1) $41.4
 $(23.8)
       
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(1.2) $51.1
 $(12.5)


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Postretirement      
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
Net actuarial loss / (gain) $(1.1) $0.4
 $(1.9) $20.9
 $(3.0) $43.8
Prior service cost —
 —
 6.8
Plan curtailment (5.7) —
 —
Reversal of amortization item:            
Net actuarial gain 0.6
 0.8
 0.7
Prior service credit (0.1) (0.1) (0.1)
Net actuarial loss (7.2) (9.8) (6.4)
Prior service cost (3.0) (3.3) (2.8)
Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(0.6) $1.1
 $(1.3) $5.0
 $(16.1) $41.4
            
Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities $(0.4) $1.2
 $(1.1) $18.5
 $(1.2) $51.1

Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 20162017 are:
$ in millions Pension Postretirement Pension
Actuarial gain / (loss) $7.2
 $(0.8)
Actuarial loss $9.7
Prior service cost $3.1
 $0.1
 $1.9

Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.

At December 31, 2015,2016, we are maintaining our long termlong-term rate of return assumption of 6.50% for pension plan assets. In addition, we are decreasing our long-termThe rate of return assumption to 3.90% from 4.50% for other postemployment benefit plan assets. These rates of return representrepresents our long-term assumptions based on our long-term portfolio mixes.mix. Also, at December 31, 2015,2016, we have increaseddecreased our assumed discount rate to 4.49%4.28% from 4.02%4.49% for pension and to 4.10% from 3.71% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in 2017 pension expense of approximately $3.5 million. A 1%one percent decrease in the rate of return assumption for pension would result in an increase in 2017 pension expense of approximately $3.5$3.5 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.2

$0.3 million to 20162017 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3$0.4 million to 20162017 pension expense. A one percent change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.

In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2015.2016. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Effective January 1, 2016, we will apply the spotapplied a disaggregated discount rate approach for determining service cost and interest cost for itsour defined benefit pension plans and other post-retirement plan. The expected 2016 service costspostretirement plans. See Note 1 – Overview and interest costs included above reflectSummary of Significant Accounting Policies for more information.

In future periods, differences in the changeactual return on pension plan assets and assumed return, or changes in methodology. The impactthe discount rate, will affect the timing of contributions, if any, to the change in approach is a reduction in: (1) expected service costs of $0.4 million for pension plans in 2016 ($0.4 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan), and (2) expected interest costs of $3.2 million for pension plans in 2016 ($3.1 million Defined Benefit Pension Plan and $0.1 million Supplemental Retirement Plan).plans.

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The weighted average assumptions used to determine benefit obligations during the years endedat December 31, 2016, 2015 2014 and 20132014 were:
Benefit Obligation Assumptions Pension Postretirement
  2015 2014 2013 2015 2014 2013
Discount rate for obligations 4.49% 4.02% 4.86% 4.10% 3.71% 4.58%
Rate of compensation increases 3.94% 3.94% 3.94% N/A N/A N/A

The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013 were:
Net Periodic Benefit
Cost / (Income) Assumptions
 Pension Postretirement
  2015 2014 2013 2015 2014 2013
Discount rate 4.02% 4.86% 4.04% 3.81% 4.51% 4.58%
Expected rate of return
on plan assets
 6.50% 6.75% 6.75% 4.50% 6.00% 6.00%
Rate of compensation increases 3.94% 3.94% 3.94% N/A N/A N/A

The assumed health care cost trend rates at December 31, 2015, 2014 and 2013 are as follows:
Health Care Cost Assumptions Expense Benefit Obligation
  2015 2014 2013 2015 2014 2013
Pre - age 65            
Current health care cost trend rate 6.97% 7.75% 8.00% 6.85% 6.97% 7.75%
             
Year trend reaches ultimate 2029 2023 2019 2036 2029 2023
Post - age 65            
Current health care cost trend rate 6.97% 6.75% 7.50% 6.85% 6.97% 6.75%
             
Year trend reaches ultimate 2029 2021 2018 2036 2029 2021
             
Ultimate health care cost trend rate 4.50% 5.00% 5.00% 4.50% 4.50% 5.00%

The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postemployment benefit cost and the accumulated postemployment benefit obligation:
Effect of change in health care cost trend rate
$ in millions 
One-percent
increase
 
One-percent
decrease
Service cost plus interest cost $0.1
 $—
Benefit obligation $1.1
 $(0.7)
Benefit Obligation Assumptions Pension
  2016 2015 2014
Discount rate for obligations 4.28% 4.49% 4.02%
Rate of compensation increases 3.94% 3.94% 3.94%

Pension plan assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.


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Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the Plan’splan’s long-term objectives. The long-term target allocations for plan assets are 18%28% – 38%48% for equity securities and 58%42% – 86%70% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds.

Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small target allocation of 6% to a core property fund, as well as a small allocation to a hedge fund.

Most of our Planplan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core property collective fund and the Common collective fund areis measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.


The following table summarizes our target pension plan allocation for 2015:2016:
 Percentage of plan assets as of December 31, 
Long-Term
Mid-Point
Target
Allocation
 Percentage of plan assets as of December 31,
Asset Category 
Long-Term
Mid-Point
Target
Allocation
 2015 2014 2016 2015
Equity Securities 28% 17% 18% 38% 37% 17%
Debt Securities 72% 67% 69% 56% 53% 67%
Real Estate —% 9% 7% 6% 10% 9%
Other —% 7% 6% —% —% 7%


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The fair values of our pension plan assets at December 31, 20152016 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2015
Asset Category
$ in millions
 Market Value at December 31, 2015 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Equity securities (a)
        
Small/Mid cap equity $9.2
 $9.2
 $—
 $—
Large cap equity 20.2
 20.2
 —
 —
International equity 18.2
 18.2
 —
 —
Emerging markets equity 2.7
 2.7
 —
 —
SIIT dynamic equity 10.0
 10.0
 —
 —
Total equity securities 60.3
 60.3
 —
 —
         
Debt Securities (b)
        
Emerging markets debt 6.3
 6.3
 —
 —
High yield bond 6.3
 6.3
 —
 —
Long duration fund 219.5
 219.5
 —
 —
Total debt securities 232.1
 232.1
 —
 —
         
Other investments (c)
        
Core property collective fund 30.2
 —
 30.2
 —
Common collective fund 22.8
 —
 22.8
 —
Total other investments 53.0
 —
 53.0
 —
         
Total pension plan assets $345.4
 $292.4
 $53.0
 $—
Fair Value Measurements for Pension Plan Assets at December 31, 2016
Asset Category
$ in millions
 Market Value at December 31, 2016 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Mutual funds:        
U.S. equities (a)
 $81.4
 $81.4
 $—
 $—
International equities (a)
 44.4
 44.4
 —
 —
Fixed income (b)
 151.1
 151.1
 —
 —
Fixed income securities        
U.S. Treasury securities 31.0
 31.0
 —
 —
Other investments:        
Core property collective fund (c)
 33.1
 —
 33.1
 —
Total pension plan assets $341.0
 $307.9
 $33.1
 $—

(a)This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies.estate. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.


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The fair values of our pension plan assets at December 31, 20142015 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2014
Asset Category
$ in millions
 Market Value at December 31, 2014 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Equity securities (a)
        
Small/Mid cap equity $10.6
 $10.6
 $—
 $—
Large cap equity 22.2
 22.2
 —
 —
International equity 18.2
 18.2
 —
 —
Emerging markets equity 2.8
 2.8
 —
 —
SIIT dynamic equity 11.6
 11.6
 —
 —
Total equity securities 65.4
 65.4
 —
 —
         
Debt Securities (b)
        
Emerging markets debt 6.0
 6.0
 —
 —
High yield bond 6.5
 6.5
 —
 —
Long duration fund 242.7
 242.7
 —
 —
Total debt securities 255.2
 255.2
 —
 —
         
Cash and cash equivalents (c)
        
Cash 1.6
 1.6
 —
 —
         
Other investments (d)
        
Core property collective fund 26.3
 —
 26.3
 —
Common collective fund 23.2
 —
 23.2
 —
Total other investments 49.5
 —
 49.5
 —
         
Total pension plan assets $371.7
 $322.2
 $49.5
 $—
Fair Value Measurements for Pension Plan Assets at December 31, 2015
Asset Category
$ in millions
 Market Value at December 31, 2015 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
Mutual funds:        
U.S. equities (a)
 $39.4
 $39.4
 $—
 $—
International equities (a)
 20.9
 20.9
 —
 —
Fixed income (b)
 232.1
 232.1
 —
 —
Other investments: (c)
        
Core property collective fund 30.2
 —
 30.2
 —
Common collective fund 22.8
 —
 22.8
 —
Total pension plan assets $345.4
 $292.4
 $53.0
 $—

(a)This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(c)This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value.
(d)This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.


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The fair values of our other postemployment benefit plan assets at December 31, 2015 by asset category are as follows:
Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2015
Asset Category
$ in millions
 Fair Value at December 31, 2015 (a) 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
JP Morgan Core Bond Fund (a)
 $2.8
 $2.8
 $—
 $—

(a)This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

The fair values of our other postemployment benefit plan assets at December 31, 2014 by asset category are as follows:
Fair Value Measurements for Other Postemployment Benefit Plan Assets at December 31, 2014
Asset Category
$ in millions
 Fair Value at December 31, 2014 (a) 
Quoted prices
in active
markets for
identical assets
 
Significant
observable
inputs
 
Significant
unobservable
inputs
    (Level 1) (Level 2) (Level 3)
JP Morgan Core Bond Fund (a)
 $3.2
 $3.2
 $—
 $—

(a)This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.

Pension funding
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. We contributed $5.0 million, $0.0$5.0 million, and $0.0 million to the pension plan during the years ended December 31, 2016, 2015 2014 and 2013,2014, respectively.

We expect to make contributions of $0.4 million to our SERP in 2016 to cover benefit payments. We also expect to contribute $1.1 million to our other postemployment benefit plans in 20162017 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January, 2016.2017.

TheFunding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, (the Act) contained new requirements for our single employer defined benefit pension plan. In additionas well as targeted funding levels necessary to establishing a 100%meet certain thresholds.

From an ERISA funding perspective, DP&L’s funded target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2015 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Actliability percentage was 112.54% and is estimated to be 112.54% until100%. In addition, DP&L must also contribute the 2016 status is certified in September 2016 fornormal service cost earned by active participants during the 2016 plan year. The Worker, Retiree, and Employer Recovery Actfunding of 2008 (WRERA),normal cost is expected to be approximately $5.7 million in 2017, which was signed into law on December 23, 2008, grantsincludes $0.6 million for plan sponsors certain relief from funding requirements and benefit restrictionsexpenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the Act.remaining annual installments, the excess is separately amortized over a seven-year period. DP&L’s funding policy for the pension plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes.


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Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated future benefit payments and Medicare Part D reimbursements
Estimated future benefit payments  
$ in millions due within the following years: Pension Postretirement Pension
2016 $24.6
 $1.7
2017 $25.2
 $1.6
 $25.0
2018 $25.8
 $1.5
 $25.5
2019 $26.3
 $1.4
 $26.0
2020 $26.7
 $1.4
 $26.4
2021 - 2025 $134.8
 $5.7
2021 $26.7
2022 - 2026 $139.6

Note 10 – Equity

Redeemable Preferred Stock
DP&L hashad 228,508 shares of $100 par value preferred stock 4,000,000outstanding at December 31, 2015 and prior to the preferred stock redemption on October 13, 2016 (see below).4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding at December 31, 2015.2016. The table below details the preferred shares outstanding at December 31, 20152016 and 2014:2015:
   December 31, 2015 and 2014 
Par Value
($ in millions)
       
Par Value
($ in millions)
 
Preferred
Stock
Rate
 
Redemption price
($ per share)
 
Shares
Outstanding
 December 31, 2015 December 31, 2014 
Preferred
Stock
Rate
 
Redemption price
($ per share)
 
Shares
Outstanding (a)
 December 31, 2016 December 31, 2015
DP&L Series A
 3.75% $102.50
 93,280
 $9.3
 $9.3
 3.75% $102.50
 93,280
 $—
 $9.3
DP&L Series B
 3.75% $103.00
 69,398
 7.0
 7.0
 3.75% $103.00
 69,398
 —
 7.0
DP&L Series C
 3.90% $101.00
 65,830
 6.6
 6.6
 3.90% $101.00
 65,830
 —
 6.6
Total     228,508
 $22.9
 $22.9
     228,508
 $—
 $22.9

(a)
DP&L's preferred stock was redeemed in October 2016. See below for more information.


The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends, of which there were none at December 31, 2015. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permitpermitted preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event iswas not solely within the control of DP&L, the preferred stock iswas presented on the Consolidated Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.

Dividend Restrictions
As long as anyOn October 13, 2016 (the "Redemption Date"), DP&L redeemed all of its issued and outstanding preferred stock, is outstanding,consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation, also contain provisions restricting the payment of cashplus, in each case an amount equal to all accrued dividends on any of its common stock if, after giving effectpayable with respect to such dividend,Preferred Stock to the aggregateRedemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all such dividends distributed subsequent to December 31, 1946 exceedsrights of the net incomeholders thereof as shareholders of DP&L available for dividends on its common stock subsequent, except the right to December 31, 1946, plus $1.2 million. This dividend restriction has historically not impacted DP&L’s ability to pay cash dividends and, as of December 31, 2015, DP&L’s retained earnings of 437.3 million were all available for common stock dividends payable to DPL.We do not expect this restriction to have an effect on the payment of cash dividends in the future.redemption price, ceased to exist. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital.

Common Stock
DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2015.2016. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. After the fixed-asset impairments recorded during the second and fourth quarters of 2016 and as of December 31, 2016, DP&L's equity ratio was 32% and its retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L.

Equity settlement of related party payable
DP&L settled a $7.5 million payable to DPL relating to income taxes. This payable balance was settled through equity and DPL's investment in DP&L was increased by $7.5 million as consideration for extinguishing the payable.

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Note 11 – Contractual Obligations, Commercial Commitments and Contingencies

DP&L – Equity Ownership Interest
DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2015,2016, DP&L could be responsible for the repayment of 4.9%, or $74.5$74.2 million, of a $1,519.9$1,514.3 million debt obligation comprised of both fixed and variable rate securities with maturities between 20162017 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015,2016, we have no knowledge of such a default.

Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2015,2016, these include:
 Payments due in: Payments due in:
$ in millions Total 
Less than
1 year
 
2 - 3
years
 
4 - 5
years
 
More than
5 years
 Total 
Less than
1 year
 
2 - 3
years
 
4 - 5
years
 
More than
5 years
DP&L:                    
Coal contracts (a)
 374.2
 186.9
 187.3
 —
 —
Coal and limestone contracts (a)
 $284.3
 $230.3
 $54.0
 $—
 $—
Purchase orders and other contractual obligations 83.8
 24.4
 30.0
 29.4
 —
 $109.8
 $43.1
 $33.6
 $33.1
 $—

(a)
Total at DP&L operated units.

Coal contracts:
DP&L has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2015, 73%2016, 92% of our future committed coal obligations are with a single supplier.two suppliers. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.


Purchase orders and other contractual obligations:
At December 31, 2015,2016, DP&L had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates.

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 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, including the matters discussed 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 as of December 31, 2015,2016, cannot be reasonably determined.

Environmental Matters
DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include:
The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions,
Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,
•
Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO2, particulates, mercury, acid gases, NOX, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,
Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs,

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Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.

In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies of approximately $0.9 million for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.

Note 12 – Related Party Transactions

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


Benefit plans
DPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.

Long-term Compensation Plan
During 2016, 2015 and 2014, many of DP&L’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units and options to purchase shares of AES common stock, however no stock options were granted in 2016. All such components vest over a three-year period and the terms of the AES restricted stock unit issued prior to 2011 also include a two year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years are not subject to a two year holding period. In addition, the performance units payable in cash are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2016, 2015 and 2014 was $0.5 million, $0.5 million and $0.0 million, respectively, and was included in “Other Operating Expenses” on DP&L’s Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on DP&L’s Balance Sheets in accordance with FASC 718 “Compensation - Stock Compensation.”

The following table provides a summary of these transactions:
 Years ended December 31, Years ended December 31,
$ in millions 2015 2014 2013 2016 2015 2014
DP&L revenues:
            
Sales to DPLER (including MC Squared) (a)
 $303.3
 $487.1
 $453.9
 $—
 $303.3
 $487.1
DP&L Operation & Maintenance Expenses:
            
Premiums paid for insurance services
provided by MVIC (b)
 $(3.2) $(2.9) $(2.9) $(3.4) $(3.2) $(2.9)
Expense recoveries for services
provided to DPLER (c)
 $2.4
 $2.2
 $5.2
 $—
 $2.4
 $2.2
Transactions with the Service Company:            
Charges for services provided $30.9
 $30.5
 $—
 $38.7
 $30.9
 $30.5
Charges to the Service Company $6.1
 $2.3
 $—
 $4.5
 $6.1
 $2.3
Transactions with other AES affiliates:      
Payments for health, welfare and benefit plans $9.4
 $14.8
 $17.1
            
Balances with related parties: At December 31, 2015 At December 31, 2014   At December 31, 2016 At December 31, 2015  
Net payable to the Service Company $(0.5) $(4.7)   $(2.0) $(0.5)  
Short-term loan with DPL Inc. $35.0
 $—
  
Deposits received from DPLER (d)
 $—
 $20.1
  
Short-term loan with DPL
 $5.0
 $35.0
  
Net prepayment with / (payable) to other AES affiliates $(2.5) $0.1
  

(a)
DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated on the sale of DPLER on January 1, 2016.

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(b)
MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC.
(c)
In the normal course of business DP&L incursincurred and recordsrecorded expenses on behalf of DPLER. Such expenses includeincluded but arewere not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently chargescharged these expenses to DPLER at DP&L’s cost and creditscredited the expense in which they were initially recorded.
(d)
DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity. Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.

Income taxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L. Under a tax sharing agreement with DPL, DP&L is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. Under this agreement, DP&L had a net receivable balance under this agreement of $9.5 million and $1.5 million and $1.0 million as ofat December 31, 20152016 and 2014,2015, respectively, which is recorded in Other current assets on the accompanying Balance Sheets.


Note 13 – Fixed-asset ImpairmentBusiness Segments

  Years ended December 31,
  2015 2014 2013
East Bend $—
 $—
 $76.0
Conesville —
 —
 10.0
Total fixed-asset impairment expense $—
 $—
 $86.0

East Bend and Conesville - During the fourth quarter of 2013,2016, DP&L’s management reassessed our separate reportable business segments in connection with recent changes in the regulatory environment, including the pending ESP case, and in preparation for the anticipated transfer of DP&L’s generation assets to AES Ohio Generation. DP&L currently manages the business through two reportable operating segments, the Transmission and Distribution ("T&D") segment and the Generation segment. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that income / (loss) from operations before income tax best reflects the underlying business performance of DP&L and is the most relevant measure considered in DP&L’s internal evaluation of the financial performance of its segments. The segments are discussed further below:

Transmission and Distribution Segment
The T&D segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 519,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. 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. The T&D segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord, Hutchings Coal, and East Bend generating facilities, which were either closed or sold in prior periods. As these assets will not be transferring to AES Ohio Generation when DP&L’s planned generation separation occurs, they are grouped with the T&D assets for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&D segment.
Generation Segment
The Generation segment is comprised of DP&L’s electric generation business. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. DP&L's generation segmentowns multiple coal-fired and peaking electric generating facilities. DP&L's generation segment sells its generated energy and capacity into the wholesale market as DP&L sources all of the generation for its SSO customers through a competitive bid process. Prior to the January 1, 2016 DPL sale of DPLER, DP&L also had full requirements sales to DPLER.

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. Certain shared and corporate costs are allocated among reporting segments.

The following tables present financial information for each of DP&L’s reportable business segments:
$ in millions T&D Generation Adjustments and Eliminations DP&L Total
Year ended December 31, 2016
Revenues from external customers $808.0
 $557.9
 $—
 $1,365.9
Intersegment revenues —
 —
 —
 —
Total revenues $808.0
 $557.9
 $—
 $1,365.9
         
Depreciation and amortization $71.0
 $49.3
 $—
 $120.3
Fixed-asset impairment (Note 14) $—
 $1,353.5
 $—
 $1,353.5
Interest expense $24.0
 $0.5
 $—
 $24.5
Income / (loss) from operations before income tax $143.6
 $(1,338.7) $—
 $(1,195.1)
         
Cash capital expenditures $83.4
 $44.9
 $—
 $128.3
         
Total assets (end of year) $1,710.5
 $324.6
 $—
 $2,035.1


$ in millions T&D Generation Adjustments and Eliminations 
DP&L Total
Year ended December 31, 2015
Revenues from external customers (a)
 $857.0
 $715.0
 $(19.7) $1,552.3
Intersegment revenues —
 186.6
 (186.6) —
Total revenues $857.0
 $901.6
 $(206.3) $1,552.3
         
Depreciation and amortization $71.5
 $66.7
 $—
 $138.2
Interest expense $28.0
 $2.9
 $—
 $30.9
Income / (loss) from operations before income tax $189.0
 $(47.5) $—
 $141.5
         
Cash capital expenditures $98.3
 $28.7
 $—
 $127.0
         
Total assets (end of year) $1,688.8
 $1,670.8
 $—
 $3,359.6

(a)Wholesale revenue for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax.
$ in millions T&D Generation Adjustments and Eliminations 
DP&L Total
Year ended December 31, 2014
Revenues from external customers (a)
 $1,021.8
 $679.0
 $(32.5) $1,668.3
Intersegment revenues —
 72.8
 (72.8) —
Total revenues $1,021.8
 $751.8
 $(105.3) $1,668.3
         
Depreciation and amortization $75.5
 $69.3
 $—
 $144.8
Interest expense $28.9
 $5.0
 $—
 $33.9
Income / (loss) from operations before income tax $242.6
 $(87.9) $—
 $154.7
         
Cash capital expenditures $100.4
 $13.8
 $—
 $114.2
         
Total assets (end of year) $1,686.1
 $1,642.7
 $—
 $3,328.8

(a)Wholesale revenue for 2014 was not restated for the impact of netting between wholesale revenue and purchased power for the Generation segment because it was impracticable to restate. This impacts the Generation revenue as well as the revenue in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax. In addition, wholesale revenue for the T&D segment in 2014 includes OVEC revenue of $32.5 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax.


Note 14 – Fixed-asset Impairment
During the years ended December 31, 2016, 2015 and 2014, DP&L had the following fixed-asset impairments:
    Years ended December 31,
  Measurement Date 2016 2015 2014
Killen December 31, 2016 $75.3
 $—
 $—
Stuart December 31, 2016 149.9
 —
 —
Miami Fort December 31, 2016 157.7
 —
 —
Zimmer December 31, 2016 91.3
 —
 —
Conesville December 31, 2016 20.8
 —
 —
Hutchings peaking facilities December 31, 2016 1.4
 —
 —
Stuart June 30, 2016 292.0
 —
 —
Killen June 30, 2016 246.2
 —
 —
Zimmer June 30, 2016 318.9
 —
 —
         
Total impairment loss   $1,353.5
 $—
 $—

Killen, Stuart, Miami Fort, Zimmer, Conesville and Hutchings peakers - December 31, 2016 - During the fourth quarter of 2016, we tested the recoverability of our long-lived coal-fired generation assets at Conesville, a 129 MW coal-fired station in Ohio, and East Bend, a 186 MW coal-fired station in Kentucky jointly-owned byone gas-fired peaking plant. Additional uncertainty around the useful life of Stuart and Killen related to the DP&L. Gradual decreases in power prices, as well as ESP proceedings along with lower estimatesexpectations of futureforward dark spreads and capacity prices in conjunction withbeyond the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment testcleared period were collectively determined to be an impairment indicator for these assets. Market information indicating that there was a significant decrease in the fair value of Zimmer and Miami Fort was determined to be an indicator of impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the gas-fired peaking plant, significant incremental capital expenditures relative to its fair value along with the fact that an impairment charge was previously taken at DPL for this facility in Q2 2016, were collectively determined to be an impairment indicator for this asset. DP&L performed a long-lived assets.asset impairment analysis for each of these asset groups and determined that their carrying amounts were not recoverable. The Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups and the Hutchings gas-fired peaking plant asset group were determined to have a fair value of $42.8 million, $57.4 million, $36.5 million, $23.7 million, $1.1 million and $1.6 million, respectively, using the market approach for Miami Fort and Zimmer and the income approach for the remaining asset groups. As a result, DP&L recognized a total pre-tax asset impairment expense of $496.4 million.

Killen, Stuart and Zimmer - June 30, 2016 - During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Stuart, Killen and Zimmer were not recoverable. The long-lived asset group subject to the impairment evaluation was determined to be each individual station of DP&L. This determination was based on the assessment of the stations’ ability to generate independent cash flows. The Conesville and East Bend asset groups of Stuart, Killen and Zimmer were each determined to have a zero fair valuevalues of $164.4 million, $84.3 million and $111.0 million, respectively, using the discounted cash flows under the income approach. As a result, DP&L recognized an asset impairment expenseexpenses of $10.0$292.0 million, $246.2 million and $76.0$318.9 million for ConesvilleStuart, Killen and East Bend,Zimmer, respectively.

Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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Item 9A – Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

We carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2016, our disclosure controls and procedures were effective.

Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
provide reasonable assurance that unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements are prevented or detected timely.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in 2013. Based on this assessment, management believes that we maintained effective internal control over financial reporting as of December 31, 2016.

Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table
Item 9B – Other Information
None.


PART III

Item 10 – Directors, Executive Officers and Corporate Governance
Not applicable pursuant to General Instruction I of Contentsthe Form 10-K.

Item 11 – Executive Compensation
Not applicable pursuant to General Instruction I of the Form 10-K.

Note
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Not applicable pursuant to General Instruction I of the Form 10-K.

Item 13 – Certain Relationships and Related Transactions, and Director Independence
Not applicable pursuant to General Instruction I of the Form 10-K.

Item 14 – Subsequent EventPrincipal Accountant Fees and Services

Accountant Fees and Services
On January 1, 2016,The following table presents the aggregate fees billed for professional services rendered to DPL closed on the sale of DPLER to IGS. Also on January 1, 2016, DP&L terminated the contract it had with DPLER for the supply of electricity. The agreement terminating the contract was signed on December 28, 2015 and DP&L received $27.7 million of restricted cash onby Ernst & Young LLP during the years ended December 31, 20152016 and 2015. Other than as set forth below, no professional services were rendered or fees billed by Ernst & Young LLP during the years ended December 31, 2016 and 2015.
  Fees billed
  Years ended December 31,
  2016 2015
Audit fees (a)
 $1,849,450
 $1,649,045
Audit-related Fees (b)
 112,900
 145,450
Tax Fees —
 —
All Other Fees —
 —
Total $1,962,350
 $1,794,495

(a)Audit fees relate to professional services rendered for the audit of our annual financial statements and the reviews of our quarterly financial statements and other services that are normally provided in connection with regulatory filing or engagements and services rendered under an agreed upon procedure engagement related to environmental studies.
(b)Audit-related fees relate to services rendered to us for assurance and related services.

The Boards of Directors of DPL Inc. and The Dayton Power and Light Company (collectively, the Board) pre-approve all audit and permitted non-audit services, including engagement fees and terms for such services in accordance with Section 10A of the Securities Exchange Act of 1934, as amended. The Board will generally pre-approve a listing of specific services and categories of services, including audit, audit-related and other services, for the early terminationupcoming or current fiscal year, subject to a specified cost level. Any material service not included in the pre-approved list of services must be separately pre-approved by the Board. In addition, all audit and permissible non-audit services in excess of the contract, which we expect to record as a gain in the first quarter of 2016. This amount is shown as Restricted cash with the associated liability shown as Advance on contract terminationpre-approved cost level, whether or not such services are included on the Balance Sheet aspre-approved list of December 31, 2015. Asservices, must be separately pre-approved by the cash we received was restricted upon receipt it is not shown on the Statement of Cash Flows.Board.


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PART IV

Item 15 – Exhibits, Financial Statements and Financial Statement Schedules
The following documents are filed as part of this report: 
1. Financial Statements 
DPL – Report of Independent Registered Public Accounting Firms
1179
DPL – Consolidated Statements of Operations for each of the three years in the period ended December 31, 20152016
1381
DPL – Consolidated Statements of Other Comprehensive Loss for each of the three years in the period ended December 31, 20152016
1482
DPL – Consolidated Balance Sheets at December 31, 20152016 and 20142015
1583
DPL – Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 20152016
1684
DPL – Consolidated StatementStatements of Shareholder’s Equity for each of the three years in the period ended December 31, 20152016
1785
DPL – Notes to Consolidated Financial Statements
1886
DP&L – Report of Independent Registered Public Accounting Firm
70135
DP&L – Statements of Operations for each of the three years in the period ended December 31, 20152016
72137
DP&L – Consolidated Statements of Other Comprehensive Income / (Loss) for each of the three years in the period ended December 31, 20152016
73138
DP&L – Balance Sheets at December 31, 20152016 and 20142015
74139
DP&L – Statements of Cash Flows for each of the three years in the period ended December 31, 20152016
75140
DP&L – StatementStatements of Shareholder’s Equity for each of the three years in the period ended December 31, 20152016
76141
DP&L – Notes to Financial Statements
77142
2. Financial Statement Schedules
Schedule II – Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2016
195
The information required to be submitted in Schedules I, III, IV and V is omitted as not applicable or not required under rules of Regulation S-X.

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Exhibits

DPL and DP&L exhibits are incorporated by reference as described unless otherwise filed as set forth herein.

The exhibits filed as part of DPL’s and DP&L’s Annual Report on Form 10-K, respectively, are:
DPLDP&L
Exhibit
Number
ExhibitLocation
X 2(a)Agreement and Plan of Merger, dated as of April 19, 2011, by and among DPL Inc., The AES Corporation and Dolphin Sub, Inc.Exhibit 2.1 to Report on Form 8-K filed April 20, 2011 (File No. 1-9052)
X 3(a)Amended Articles of Incorporation of DPL Inc., as amended through January 6, 2012Exhibit 3(a) to Report on Form 10-K for the year ended December 31, 2011 (File No. 1-2385)
X 3(b)Amended Regulations of DPL Inc., as amended through November 28, 2011Exhibit 3.2 to Report on Form 8-K filed November 28, 2011 (File No. 1-9052)
 X3(c)Amended Articles of Incorporation of The Dayton Power and Light Company, as of January 4, 1991Exhibit 3(b) to Report on Form 10-K/A for the year ended December 31, 1991 (File No. 1-2385)
 X3(d)Regulations of The Dayton Power and Light Company, as of April 9, 1981Exhibit 3(a) to Report on Form 8-K filed on May 3, 2004 (File No. 1-2385)
XX4(a)Composite Indenture dated as of October 1, 1935, between The Dayton Power and Light Company and Irving Trust Company, Trustee with all amendments through the Twenty-Ninth Supplemental IndentureExhibit 4(a) to Report on Form 10-K for the year ended December 31, 1985 (File No. 1-2385)
XX4(b)Forty-First Supplemental Indenture dated as of February 1, 1999, between The Dayton Power and Light Company and The Bank of New York, TrusteeExhibit 4(m) to Report on Form 10-K for the year ended December 31, 1998 (File No. 1-2385)
XX4(c)Forty-Second Supplemental Indenture dated as of September 1, 2003, between The Dayton Power and Light Company and The Bank of New York, TrusteeExhibit 4(r) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)
XX4(d)Forty-Third Supplemental Indenture dated as of August 1, 2005, between The Dayton Power and Light Company and The Bank of New York, TrusteeExhibit 4.4 to Report on Form 8-K filed August 24, 2005 (File No. 1-2385)
X 4(e)Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, TrusteeExhibit 4(a) to Registration Statement No. 333-74630
X 4(f)First Supplemental Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, as TrusteeExhibit 4(b) to Registration Statement No. 333-74630
X 4(g)Amended and Restated Trust Agreement dated as of August 31, 2001 among DPL Inc., The Bank of New York, The Bank of New York (Delaware), the administrative trustees named therein, and several Holders as defined thereinExhibit 4(c) to Registration Statement No. 333-74630
XX4(h)Forty-Fourth Supplemental IndentureLoan Agreement, dated as of September 1, 2006, by and between the Bank of New York, TrusteeOhio Air Quality Development Authority and The Dayton Power and Light CompanyExhibit 4(s)4.1 to Report on Form 10-K for the year ended December 31, 20098-K filed September 19, 2006 (File No. 1-2385)

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DPLDP&L
Exhibit
Number
ExhibitLocation
XX4(i)Forty-Fourth Supplemental Indenture dated as of September 1, 2006 between the Bank of New York, Trustee and The Dayton Power and Light CompanyExhibit 4.2 to Report on Form 8-K filed September 19, 2006 (File No. 1-2385)
X4(j)Indenture, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National AssociationExhibit 4.1 to Report on Form 8-K filed October 5, 2011 by The AES Corporation (File No. 1-12291)
X 4(j)4(k)Supplemental Indenture, dated as of November 28, 2011, between DPL Inc. and Wells Fargo Bank, National AssociationExhibit 4(k) to Report on Form 10-K for the year ended December 31, 2011 (File No. 1-2385)
X 4(k)Registration Rights Agreement, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Merrill Lynch Pierce Fenner & Smith Incorporated and each of the initial purchasers named thereinExhibit 4(l) to Report on Form 10-K for the year ended December 31, 2011 (File No. 1-2385)
X4(l)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 purchasersExhibit 4.1 to Report on Form 8-K filed September 25, 2013 (File No. 1-2385)
X4(m)47th 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 CompanyExhibit 4.2 to Report on Form 8-K filed September 25, 2013 (File No. 1-2385)
X4(n)Indenture, dated October 6, 2014, between DPL Inc. and U.S. Bank National Association.Exhibit 4.1 to Report on Form 8-K filed October 10, 2014 (File No. 1-9052)
X4(o)Registration Rights Agreement, dated as of October 6, 2014, by and between DPL Inc. and 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 October 10, 2014 (File No. 1-9052)
XX4(p)4(m)Loan Agreement, dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series A pollution control bondsExhibit 4.1 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
XX4(q)4(n)Loan Agreement, dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series B pollution control bondsExhibit 4.2 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
XX4(r)4(o)Forty-Eighth Supplemental Indenture dated as of August 1, 2015 between The Bank of New York Mellon, Trustee and The Dayton Power and Light CompanyExhibit 4.3 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
XX4(s)4(p)Forty-Ninth Supplemental Indenture dated as of August 1, 2015 between The Bank of New York Mellon, Trustee and The Dayton Power and Light CompanyExhibit 4.4 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)

124
Table of Contents

DPLDP&L
Exhibit
Number
ExhibitLocation
XX4(t)4(q)Bond Purchase and Covenants Agreement, dated as of August 3,1, 2015, among The Dayton Power and Light Company, SunTrust Bank, as Administrative Agent, and the several lenders from time to time party theretoExhibit 4.5 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
XX4(r)Amendment dated as of February 21, 2017 to Bond Purchase and Covenants Agreement by and among The Dayton Power and Light Company, SunTrust Bank, as Administrative Agent, and several lenders from time to time party thereto, dated as of August 1, 2015Filed herewith as Exhibit 4(r)
XX4(s)Fiftieth Supplemental Indenture, dated as of August 1, 2016, by and between The Dayton Power and Light Company and The Bank of New York Mellon, TrusteeExhibit 4.3 to Report on Form 8-K filed August 30, 2016 (File No. 1-2385)

DPLDP&L
Exhibit
Number
ExhibitLocation
X 10(a)Credit Agreement, dated as of July 31, 2015, among DPL Inc., U.S. Bank National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and an L/C Issuer, PNC Bank, National Association, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit AgreementExhibit 10.1 to Report on Form 8-K filed August 6, 2015 (File No. 1-9052)
X 10(b)Guaranty Agreement, dated as of July 31, 2015, between DPL Energy, LLC and U.S. Bank National Association, as Administrative AgentExhibit 10.2 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X 10(c)Pledge Agreement, dated as of July 31, 2015, between DPL Inc. and U.S. Bank National Association, as Collateral AgentExhibit 10.3 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
X 10(d)Open-end Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing, dated as of July 31, 2015, made by DPL Energy LLC to U.S. Bank National Association, as Collateral Agent and MortgageeExhibit 10.4 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
XX10(e)Credit Agreement, dated as of July 31, 2015, among The Dayton Power and Light Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Fifth Third Bank, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit AgreementExhibit 10.5 to Report on Form 8-K filed August 6, 2015 (File No. 1-2385)
XX10(f)Amendment dated as of February 21, 2017 to Credit Agreement by and among The Dayton Power and Light Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Fifth Third Bank, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement, dated as of July 31, 2015Filed herewith as Exhibit 10(f)
X10(g)Open-End Leasehold Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing from DPL Energy, LLC to U.S. Bank National Association, dated as of October 29, 2015Exhibit 10(a) to Report on Form 10-Q for the quarter ended September 30, 2015 (File No. 1-9052)

DPLDP&L
Exhibit
Number
ExhibitLocation
XX10(h)Credit Agreement, dated August 24, 2016, among The Dayton Power and Light Company, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent and collateral agent, Morgan Stanley Senior Funding, Inc., as a lender and BMO Capital Markets Corp., Fifth Third Securities, The Huntington National Bank, PNC Capital Markets LLC, RBC Capital Markets, LLC, Regions Capital Markets, a division of Regions Bank, and SunTrust Robinson Humphrey, Inc., as managing agentsExhibit 4.1 to Report on Form 8-K filed August 30, 2016 (File No. 1-2385)
XX10(i)Pledge and Security Agreement, dated as of August 24, 2016, between The Dayton Power and Light Company and JPMorgan Chase Bank, N.A., as collateral agentExhibit 4.2 to Report on Form 8-K filed August 30, 2016 (File No. 1-2385)
XX10(j)Stipulation and Recommendation dated January 30, 2017Exhibit 10.1 to Report on Form 8-K filed February 3, 2017 (File No. 1-2385)
X 31(a)Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 31(a)
X 31(b)Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 31(b)
 X31(c)Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 31(c)
 X31(d)Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 31(d)
X 32(a)Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 32(a)

125
Table of Contents

DPLDP&L
Exhibit
Number
ExhibitLocation
X 32(b)Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 32(b)
 X32(c)Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 32(c)
 X32(d)Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002Filed herewith as Exhibit 32(d)
XX101.INSXBRL InstanceFurnished herewith as Exhibit 101.INS
XX101.SCHXBRL Taxonomy Extension SchemaFurnished herewith as Exhibit 101.SCH
XX101.CALXBRL Taxonomy Extension Calculation LinkbaseFurnished herewith as Exhibit 101.CAL
XX101.DEFXBRL Taxonomy Extension Definition LinkbaseFurnished herewith as Exhibit 101.DEF
XX101.LABXBRL Taxonomy Extension Label LinkbaseFurnished herewith as Exhibit 101.LAB
XX101.PREXBRL Taxonomy Extension Presentation LinkbaseFurnished herewith as Exhibit 101.PRE


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

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, we have not filed as an exhibit to ourthis Form 10-K certain instruments with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of us and our subsidiaries on a consolidated basis, but we hereby agree to furnish to the SEC on request any such instruments.

126
Item 16 – Form 10-K Summary
None.


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.
  
  
  
March 16, 2016February 24, 2017/s/ Kenneth J. Zagzebski
 Kenneth J. Zagzebski
 President and Chief Executive Officer
 (principal executive officer)
  
  
 The Dayton Power and Light Company
  
  
  
March 16, 2016February 24, 2017/s/ Thomas A. Raga
 Thomas A. Raga
 President and Chief Executive Officer
 (principal executive officer)


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of DPL Inc. and in the capacities and on the dates indicated.

127
/s/ Brian A. MillerDirector and ChairmanFebruary 24, 2017
Brian A. Miller
/s/ Elizabeth HackensonDirectorFebruary 24, 2017
Elizabeth Hackenson
/s/ Michael S. MizellDirectorFebruary 24, 2017
Michael S. Mizell
/s/ Kazi K. HasanDirectorFebruary 24, 2017
Kazi K. Hasan
/s/ Mary StawikeyDirectorFebruary 24, 2017
Mary Stawikey
/s/ Kenneth J. ZagzebskiDirector, President and Chief Executive OfficerFebruary 24, 2017
Kenneth J. Zagzebski(principal executive officer)
/s/ Craig L. JacksonChief Financial OfficerFebruary 24, 2017
Craig L. Jackson(principal financial officer)
/s/ Kurt A. TornquistControllerFebruary 24, 2017
Kurt A. Tornquist(principal accounting officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of The Dayton Power and Light Company and in the capacities and on the dates indicated.

/s/ Brian A. MillerDirector and ChairmanFebruary 24, 2017
Brian A. Miller
/s/ Kenneth J. ZagzebskiDirectorFebruary 24, 2017
Kenneth J. Zagzebski
/s/ Elizabeth HackensonDirectorFebruary 24, 2017
Elizabeth Hackenson
/s/ Michael S. MizellDirectorFebruary 24, 2017
Michael S. Mizell
/s/ Kazi K. HasanDirectorFebruary 24, 2017
Kazi K. Hasan
/s/ Paul L. FreedmanDirectorFebruary 24, 2017
Paul L. Freedman
/s/ Tish D. MendozaDirectorFebruary 24, 2017
Tish D. Mendoza
/s/ Thomas A. RagaDirector, President and Chief Executive OfficerFebruary 24, 2017
Thomas A. Raga(principal executive officer)
/s/ Craig L. JacksonDirector, Vice President and Chief Financial OfficerFebruary 24, 2017
Craig L. Jackson(principal financial officer)
/s/ Kurt A. TornquistControllerFebruary 24, 2017
Kurt A. Tornquist(principal accounting officer)

Schedule II
DPL Inc.
VALUATION AND QUALIFYING ACCOUNTS
For each of the three years ended December 31, 2016
$ in thousands
Description 
Balance at
Beginning
of Period
 Additions 
Deductions (a)
 
Balance at
End of Period
Year ended December 31, 2016        
Deducted from accounts receivable -        
Provision for uncollectible accounts (b)
 $835
 $4,113
 $3,789
 $1,159
Deducted from deferred tax assets -        
Valuation allowance for deferred tax assets $17,246
 $—
 $13,921
 $3,325
Year ended December 31, 2015        
Deducted from accounts receivable -        
Provision for uncollectible accounts (b)
 $898
 $3,766
 $3,829
 $835
Deducted from deferred tax assets -        
Valuation allowance for deferred tax assets $18,900
 $1,626
 $3,280
 $17,246
Year ended December 31, 2014        
Deducted from accounts receivable -        
Provision for uncollectible accounts (b)
 $909
 $4,011
 $4,022
 $898
Deducted from deferred tax assets -        
Valuation allowance for deferred tax assets $13,721
 $5,179
 $—
 $18,900

(a)Amounts written off, net of recoveries of accounts previously written off 
(b)Provision for uncollectible accounts related to Company's held-for-sale business as detailed below were excluded from the table above and were included in "Assets held for sale - current" in the consolidated balance sheets. 
  For the years ended, December 31 
  2015 2014 
 Beginning balance$369
 $251
 
 Additions2,035
 3,633
 
 Deductions2,291
 3,515
 
 Ending balance$113
 $369
 


THE DAYTON POWER AND LIGHT COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For each of the three years ended December 31, 2016
$ in thousands
Description 
Balance at
Beginning
of Period
 Additions 
Deductions (a)
 
Balance at
End of Period
Year ended December 31, 2016        
Deducted from accounts receivable -        
Provision for uncollectible accounts $835
 $4,113
 $3,789
 $1,159
Year ended December 31, 2015        
Deducted from accounts receivable -        
Provision for uncollectible accounts $897
 $3,766
 $3,828
 $835
Year ended December 31, 2014        
Deducted from accounts receivable -        
Provision for uncollectible accounts $909
 $4,011
 $4,023
 $897

(a)Amounts written off, net of recoveries of accounts previously written off.

196