UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q


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


For the quarterly period ended September 30, 2017March 31, 2021


OR


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


For the transition period from ____________ to ____________

DPL Inc.
(an Ohio corporation)

Commission File Number 1-9052

1065 Woodman Drive
Dayton, Ohio 45432

937-259-7215

IRS Employer Identification No. 31-1163136


dpl-20210331_g1.jpg

THE DAYTON POWER AND LIGHT COMPANY
d/b/a AES Ohio
(an Ohio corporation)

Commission File Number 1-2385

1065 Woodman Drive
Dayton, Ohio 45432

937-259-7215

IRS Employer Identification No. 31-0258470
Commission
File Number
Registrant, StateSecurities registered pursuant to Section 12(b) of Incorporation,
Address and Telephone Number
I.R.S. Employer
Identification No.the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange on Which Registered
1-9052N/AN/ADPL INC.31-1163136N/A
(An Ohio Corporation)
1065 Woodman Drive
Dayton, Ohio 45432
937-259-7215
1-2385THE DAYTON POWER AND LIGHT COMPANY31-0258470
(An Ohio Corporation)
1065 Woodman Drive
Dayton, Ohio 45432
937-259-7215


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.
Yeso
☐
Nox☑
The Dayton Power and Light Company
Yeso
☐
Nox☑


Each ofThe Dayton Power and Light Company is a voluntary filer. DPL Inc. was a voluntary filer until its Registration Statement on Form S-4 filed with the Securities and Exchange Commission on March 15, 2021 was declared effective on March 31, 2021.  DPL Inc. and The Dayton Power and Light Company is a voluntary filer that 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
DPL Inc.
Yesx
☑
Noo☐
The Dayton Power and Light Company
Yesx
☑
Noo☐


1


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

accelerated
filer

Filer
Accelerated
filer

Filer
Non-
accelerated
filer
(Do not check if a smaller reporting company)
Non-accelerated Filer
Smaller

reporting

company
Emerging growth company
DPL Inc.o☐o☐x☑o☐o☐
Large
accelerated
Filer		Accelerated
Filer		Non-accelerated FilerSmaller
reporting
company		Emerging growth company
The Dayton Power and Light Companyo☐o☐x☑o☐o☐


If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
DPL Inc.o☐
The Dayton Power and Light Companyo☐


Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
DPL Inc.
Yeso
☐
Nox☑
The Dayton Power and Light Company
Yeso
☐
Nox☑


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


As of November 1, 2017,May 5, 2021, each registrant had the following shares of common stock outstanding:
RegistrantDescriptionShares Outstanding
RegistrantDescriptionShares Outstanding
DPL Inc.Common Stock, no par value1
The Dayton Power and Light CompanyCommon Stock, $0.01 par value41,172,173


2

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




3
2


DPL Inc. and The Dayton Power and Light CompanyAES Ohio

Table of Contents
Quarterly Report on Form 10-Q
QuarterQuarter Ended September 30, 2017

March 31, 2021
Table of ContentsPage No.
Glossary of Terms
Forward-Looking Statements
Part I Financial Information
Item 1Financial Statements – DPL Inc. and The Dayton Power and Light Company (Unaudited)
DPL Inc.
DPL Inc.
Condensed Consolidated Statements of Operations
Condensed Consolidated Statements of Comprehensive Income / (Loss)
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Cash Flows
Condensed Consolidated Statements of Shareholder's Deficit
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1 – Overview and Summary of Significant Accounting Policies
The Dayton Power and Light CompanyNote 2 – Supplemental Financial Information
Note 3 – Regulatory Matters
Note 4 – Fair Value
Note 5 – Derivative Instruments and Hedging Activities
Note 6 – Long-term Debt
Note 7 – Income Taxes
Note 8 – Benefit Plans
Note 9 – Contractual Obligations, Commercial Commitments and Contingencies
Note 10 – Business Segments
Note 11 – Revenue
Note 12 – Discontinued Operations
Note 13 – Risks and Uncertainties
AES Ohio
Condensed Statements of Operations
Condensed Statements of Comprehensive Income / (Loss)
Condensed Balance Sheets
Condensed Statements of Cash Flows
Condensed Statements of Shareholder's Equity
Notes to Unaudited Condensed Financial Statements
Note 1 – Overview and Summary of Significant Accounting Policies
Note 2 – Supplemental Financial Information
Note 3 – Regulatory Matters
Note 4 – Fair Value
Note 5 – Derivative Instruments and Hedging Activities
Note 6 – Long-term Debt
Note 7 – Income Taxes
Note 8 – Benefit Plans
Note 9 – Shareholder's Equity
Note 10 – Contractual Obligations, Commercial Commitments and Contingencies
Note 11 – Revenue
Note 12 – Risks and Uncertainties
Item 2
Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations
Electric Sales and Customers
110
Item 3
Quantitative and Qualitative Disclosures about Market Risk
Item 4
Controls and Procedures


3

DPL Inc. and The Dayton Power and Light Company

Table of Contents (cont.)
Quarterly Report on Form 10-Q
Quarter Ended September 30, 2017

Page No.
Part II Other Information
Item 1Legal Proceedings
111
Item 1ARisk Factors
111
Item 2
Unregistered Sales of Equity Securities and Use of Proceeds
Item 3
Defaults Upon Senior Securities 
Item 4
Mine Safety Disclosures
Item 5Other Information
112
Item 6Exhibits
113
Other
Signatures
114



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Table of Contents

GLOSSARY OF TERMS 


The following terms are used in this Form 10-Q:
TermDefinition
AES2017 ESPDP&L's ESP - approved October 20, 2017, effective November 1, 2017
AESThe AES Corporation - a global power company and the ultimate parent company of DPL
AES OhioThe Dayton Power and Light Company, which does business as AES Ohio
AES Ohio GenerationAES Ohio Generation, LLC a wholly-owned subsidiary of DPL that owns and operates generation facilities from which it makes wholesale sales
AOCIAccumulated Other Comprehensive Income
AROAsset Retirement Obligation
ASUAccounting Standards Update
CAAU.S. Clean Air Act
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. DP&L’s capacity is located in the “rest of” RTO area of PJM.
CCRCoal combustion residuals
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 units operate under the CP construct effective June 1, 2016.
CPPClean Power Plan
D.C. Circuit CourtUnited States Court of Appeals for the District of Columbia Circuit
DPLDPL Inc.
DPLERDPL Energy Resources, Inc., formerly- a wholly-owned subsidiary of DPL, which sold competitive electric energypreviously operated EGUs and other energy services. DPLERmade wholesale sales
AOCIAccumulated Other Comprehensive Income
AOCLAccumulated Other Comprehensive Loss
AROAsset Retirement Obligation
ASUAccounting Standards Update
CAAU.S. Clean Air Act - the congressional act that directs the USEPA’s regulation of stationary and mobile sources of air pollution to protect air quality and stratospheric ozone
CCRCoal Combustion Residuals
ConesvilleAES Ohio Generation's interest in Unit 4 at the Conesville EGU. This was sold by DPL on January 1, 2016. The DPLER sale agreement was signed on December 28, 2015.June 5, 2020.
COVID-19The disease caused by the novel coronavirus that resulted in a global pandemic in 2020.
CSAPRCross-State Air Pollution Rule - the USEPA's rule to address interstate air pollution transport to decrease emissions to downwind states
DMRDistribution Modernization Rider - established in the ESP as a non-bypassable rider to collect $105.0 million in revenue per year for the first three years of the ESP term
DPLDPL Inc.
DP&LThe Dayton Power and Light Company - the principal subsidiary of DPL and a public utility that delivers electricity to residential, commercial, industrial and governmental customers in a 6,000 square6,000-square mile area of West Central OhioOhio. DP&L does business as AES Ohio.
DthsDRODecatherms, unit of heat energy equal to 10 therms. One therm is equal to 100,000 British Thermal UnitsDistribution Rate Order - the order issued by the PUCO on September 26, 2018 establishing new base distribution rates for DP&L, which became effective October 1, 2018
EBITDAEarnings before interest, taxes, depreciation and amortization. EBITDA also excludes the Fixed-asset impairment
EGUElectric Generating Unit
ERISAThe Employee Retirement Income Security Act of 1974
ESPThe Electric Security Plan is- a plan that a utility must file with the PUCO to establish SSO rates pursuant to Ohio law
ESP 1ESP originally 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.2009. After DP&L withdrew its 2017 ESP 2Application, the PUCO approved DP&L's request to revert to rates based on July 27, 2016 and filed to reinstate previously authorized rates fromits ESP 1 rate plan effective December 19, 2019. DP&L is currently operating under this ESP 1 plan.
ESP 3FASBESP filed with the PUCO by DP&L on February 22, 2016 and an amended application filed on October 11, 2016
FASBFinancial Accounting Standards Board
FASCFASB Accounting Standards Codification
FERCFederal Energy Regulatory Commission
FGDFlue Gas Desulfurization
Form 10-KDPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, 2016,2020, which was filed on February 28, 2017


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24, 2021
GLOSSARY OF TERMS (cont.)
TermDefinition
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
FTRGAAPFinancial Transmission Right
GAAPGenerally Accepted Accounting Principles in the United States of America
Generation Separation
The transfer on October 1, 2017 to AES Ohio Generation of the DP&L-owned generating facilities and related liabilities pursuant to an asset contribution agreement with a subsidiary that was then merged into AES Ohio Generation
GHGkWhGreenhouse GasKilowatt-hours - a measure of electrical energy equivalent to a power consumption of 1,000 watts for 1 hour
kVLIBORKilovolt, 1,000 volts
kWhKilowatt-hours
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
MergerMATSMercury and Air Toxics Standards - the USEPA’s rules for existing and new power plants under Section 112 of the CAA
MergerThe merger of DPL and Dolphin Sub, Inc., a wholly-owned subsidiary of AES. On November 28, 2011, DPL became a wholly-owned subsidiary of AES.
MROMiami Valley LightingMiami Valley Lighting, LLC is a wholly-owned subsidiary of DPL established in 1985 to provide street and outdoor lighting services to customers in the Dayton region. Miami Valley Lighting serves businesses, communities and neighborhoods in West Central Ohio with over 70,000 lighting solutions for more than 190 businesses and 180 local governments.
MROMarket Rate Option - a market-based plan that a utility may file with PUCO to establish SSO rates pursuant to Ohio law
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Table of Contents
MTMMark to MarketGLOSSARY OF TERMS (cont.)
MVIC
TermDefinition
MVICMiami Valley Insurance Company is a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies related to jointly-owned facilities operated by DP&L
MWMegawatt, a unit of power equal to one million watts
MWhNAAQSMegawatt-hour
NAVNet asset value
NAAQSNational Ambient Air Quality Standards - the USEPA’s health and environmental based standards for six specified pollutants, as found in the ambient air
NERCNorth American Electric Reliability Corporation - a not-for-profit international regulatory authority whose mission is to assure the effective and efficient reduction of risks to the reliability and security of the electric grid
Non-bypassableNOxCharges that are assessed to all customers regardless of whomNitrogen Oxide - an air pollutant regulated by the customer selects as their retail electric generation supplierNAAQS under the CAA
NOVNotice of Violation
NOx
Nitrogen Oxide
NPDESNational Pollutant Discharge Elimination System
NSPSNew Source Performance Standards
NYMEXNew York Mercantile Exchange
Ohio EPAOhio Environmental Protection Agency
OTCOVECOver-The-Counter
OVECOhio Valley Electric Corporation - an electric generating company in which DP&L holds a 4.9% equity interest
PJMPeaker assetsThe generation and related assets for the 586.0 MW Tait combustion turbine and diesel generation facility, the 236.0 MW Montpelier combustion turbine generation facility, the 101.5 MW Yankee combustion turbine generation and solar facility, the 25.0 MW Hutchings combustion turbine generation facility, the 12.0 MW Monument diesel generation facility, and the 12.0 MW Sidney diesel generation facility that were sold on March 27, 2018
PJMPJM Interconnection, LLC, an RTO
PUCOPublic Utilities Commission of Ohio
RPMRSCReliability Pricing Model. The Reliability Pricing Model was PJM’s capacity construct priorRate Stabilization Charge is a non-bypassable rider intended to the implementation of the CP program.compensate DP&L for providing stabilized rates to customers.
RTORegional Transmission Organization - an entity that is independent from all generation and power marketing interests and has exclusive responsibility for grid operations, short-term reliability, and transmission service within a region
SCRSECSelective Catalytic Reduction
SECU.S. Securities and Exchange Commission
SEETSERPSignificantly excessive earnings test
SERPSupplemental Executive Retirement Plan


6
Table of Contents

GLOSSARY OF TERMS (cont.)
TermDefinition
Service CompanyAES US Services, LLC - the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses
SO2
SSO		Sulfur Dioxide
SSOStandard Service Offer represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers that take retail generation service from DP&L within DP&L’s service territory
T&DDP&L’s electric transmissionTransmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers
USEPATCJAThe Tax Cuts and Jobs Act of 2017, signed on December 22, 2017
U.S.United States of America
USEPAU.S. Environmental Protection Agency
USDUSFU.S. dollar
USFThe Universal Service Fund 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.U.S. and Utilities Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL
Utility segmentDPL's Utility segment is made up of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers


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 accountconsidering 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•impacts of weather and catastrophic weather-related damage;on retail sales;
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;
availability and price of capacity;
state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws;
compliance with, changes in and liabilities under 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;

•weather-related damage to our electrical system;
•performance of our suppliers;
•transmission and distribution system reliability and capacity;
•regulatory actions and outcomes, including, but not limited to, the review and approval of our rates and charges by the PUCO;
•federal and state legislation and regulations;

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Table of Contents

changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
financial market conditions, changes in interest rates and •changes in our credit ratings or the credit ratings of AES;
•fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and our ability to fund defined benefit pension plans;
•changes in financial or regulatory accounting policies;
•environmental matters, including costs of compliance with, and liabilities related to, current and future environmental laws and requirements;
•interest rates and the use of interest rate hedges, inflation rates and other costs of capital;
•the availability of capital;
•the ability of subsidiaries to pay dividends or distributions to DPL;
•level of creditworthiness of counterparties to contracts and transactions;
•labor strikes or other workforce factors, including the ability to attract and retain key personnel;
•facility or equipment maintenance, repairs and capital expenditures;
•significant delays or unanticipated cost increases associated with construction projects;
•the availability and cost of capital;funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material;
•local economic conditions;
•costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;
•industry restructuring, deregulation and competition;
•issues related to our participation in PJM, including the cost associated with membership, allocation of costs, costs associated with transmission expansion, the recovery of costs incurred and the risk of default of other PJM participants;
•changes in tax laws and the effects of our strategies to reduce tax payments;strategies;
•product development, technology changes and changes in prices of products and technologies;
•cyberattacks and information security breaches;
•the outcomesuse of litigationderivative contracts;
•catastrophic events such as fires, explosions, terrorist acts, acts of war, pandemic events, including the outbreak of COVID-19, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snowstorms, droughts or other similar occurrences; and regulatory investigations, proceedings or inquiries;
general economic conditions; and
•the risks and other factors discussed in this report and other DPL and DP&Lfilings with the SEC.


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


All suchof the above factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See Item 1A - Risk Factors to Part I in our Annual Report on Form 10-K for the fiscal year ended December 31, 20162020 and the “Management’s“Management's Discussion and Analysis of Financial Condition and Results of Operations” section in such report and in our Quarterly Reports on Form 10-Q for the quarters ended June 30, and March 31, 2017 and this Quarterly Report on Form 10-Q for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook. These risks may also be specifically described in our Quarterly Reports on Form 10-Q in Part II - Item 1A, Current Reports on Form 8-K and other documents that we may file from time to time with the SEC.


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


COMPANY WEBSITESWEBSITE


DPL’sDP&L’s public internet site is www.dplinc.com. DP&L’s public internet site is www.dpandl.com.www.aes-ohio.com. The information on these websitesthis website is not incorporated by reference into this report.


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



Item 1 – Financial Statements


8
Table of Contents

























FINANCIAL STATEMENTS


DPL INC.




9
Table of Contents

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues $323.9
 $389.3
 $945.9
 $1,081.6
         
Cost of revenues:        
Net fuel cost 57.3
 78.9
 165.4
 206.0
Net purchased power cost 84.0
 111.7
 263.4
 330.5
Total cost of revenues 141.3
 190.6
 428.8
 536.5
         
Gross margin 182.6
 198.7
 517.1
 545.1
         
Operating expenses:        
Operation and maintenance 81.9
 91.5
 250.3
 257.2
Depreciation and amortization 27.3
 30.9
 81.8
 100.3
General taxes 20.1
 21.6
 68.3
 64.2
Fixed-asset impairment —
 —
 66.4
 235.5
Loss / (gain) on asset disposal (0.3) —
 15.9
 0.1
Other (5.2) (0.7) (6.1) (0.7)
Total operating expenses 123.8
 143.3
 476.6
 656.6
         
Operating income / (loss) 58.8
 55.4
 40.5
 (111.5)
         
Other income / (expense), net        
Investment income 0.1
 0.1
 0.2
 0.3
Interest expense (27.2) (27.0) (81.5) (79.3)
Charge for early redemption of debt (3.0) (0.5) (3.3) (3.1)
Other expense (0.7) (0.2) (2.3) (0.9)
Total other expense, net (30.8) (27.6) (86.9) (83.0)
         
Income / (loss) from continuing operations before income tax 28.0
 27.8
 (46.4) (194.5)
         
Income tax expense / (benefit) from continuing operations 6.1
 12.7
 (17.1) (75.0)
         
Net income / (loss) from continuing operations 21.9
 15.1
 (29.3) (119.5)
         
Discontinued operations (Note 12)        
Loss from discontinued operations —
 —
 —
 (0.7)
Gain from disposal of discontinued operations —
 —
 —
 49.2
Income tax expense for discontinued operations —
 —
 —
 18.9
Net income from discontinued operations —
 —
 —
 29.6
         
Net income / (loss) $21.9
 $15.1
 $(29.3) $(89.9)

DPL INC.
Condensed Consolidated Statements of Operations
(Unaudited)
Three months ended
March 31,
$ in millions20212020
Revenues$175.2 $171.2 
Operating costs and expenses
Net fuel cost0.4 0.6 
Net purchased power cost71.5 62.8 
Operation and maintenance34.9 47.1 
Depreciation and amortization19.1 17.7 
Taxes other than income taxes20.4 20.9 
Other, net(0.1)(0.1)
Total operating costs and expenses146.2 149.0 
Operating income29.0 22.2 
Other income / (expense), net:
Interest expense(15.6)(18.9)
Other income / (expense)0.5 (0.9)
Total other expense, net(15.1)(19.8)
Income from continuing operations before income tax13.9 2.4 
Income tax benefit from continuing operations(0.3)(0.1)
Net income from continuing operations14.2 2.5 
Discontinued operations (Note 12):
Loss from discontinued operations before income tax(0.8)(0.7)
Income tax benefit from discontinued operations(0.2)(0.1)
Net loss from discontinued operations(0.6)(0.6)
Net income$13.6 $1.9 
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.


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DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
  Three months ended September 30, Nine months ended
September 30,
$ in millions 2017 2016 2017 2016
Net income / (loss) $21.9
 $15.1
 $(29.3) $(89.9)
Available-for-sale securities activity:        
Change in fair value of available-for-sale securities, net of income tax expense of $(0.1), $0.0, $(0.2) and $(0.1) for each respective period 0.1
 0.1
 0.4
 0.2
Reclassification to earnings, net of income tax expense of $0.0 for each respective period —
 —
 (0.1) —
Total change in fair value of available-for-sale securities 0.1
 0.1
 0.3
 0.2
Derivative activity:        
Change in derivative fair value, net of income tax expense of $(0.8), $(5.2), $(6.6) and $(12.3) for each respective period 1.4
 9.5
 12.1
 22.4
Reclassification to earnings, net of income tax benefit of $1.3, $3.0, $3.3 and $13.8 for each respective period (2.4) (5.5) (6.0) (24.4)
Total change in fair value of derivatives (1.0) 4.0
 6.1
 (2.0)
Pension and postretirement activity:        
Prior service cost for the period, net of income tax benefit of $0.0, $0.0, $0.2 and $0.0 for each respective period —
 —
 (0.3) —
Net loss for period, net of income tax benefit of $0.0, $0.0, $0.7 and $0.0 for each respective period —
 —
 (1.2) —
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $(0.5) and $(0.1) for each respective period —
 —
 0.9
 0.1
Total change in unfunded pension obligation —
 —
 (0.6) 0.1
         
Other comprehensive income / (loss) (0.9) 4.1
 5.8
 (1.7)
         
Net comprehensive income / (loss) $21.0
 $19.2
 $(23.5) $(91.6)

DPL INC.
Condensed Consolidated Statements of Comprehensive Income
(Unaudited)
Three months ended
March 31,
$ in millions20212020
Net income$13.6 $1.9 
Derivative activity:
Change in derivative fair value, net of income tax expense of $0.0 and $0.0 for each respective period0 (0.3)
Reclassification to earnings, net of income tax expense of $0.0 and $0.1 for each respective period(0.2)(0.3)
Total derivative activity(0.2)(0.6)
Pension and postretirement activity:
Reclassification to earnings, net of income tax benefit of $(0.1) and $0.0 for each respective period0.5 0.3 
Total change in unfunded pension and postretirement obligations0.5 0.3 
Other comprehensive income / (loss)0.3 (0.3)
Net comprehensive income$13.9 $1.6 
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.




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DPL INC.DPL INC.DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
Condensed Consolidated Balance SheetsCondensed Consolidated Balance Sheets
(Unaudited)(Unaudited)
$ in millions September 30, 2017 December 31, 2016$ in millionsMarch 31, 2021December 31, 2020
ASSETS    ASSETS  
Current assets:    Current assets:
Cash and cash equivalents $23.4
 $54.6
Cash and cash equivalents$34.1 $25.4 
Restricted cash 2.0
 29.0
Restricted cash0.1 0.1 
Accounts receivable, net (Note 2) 111.4
 135.1
Inventories (Note 2) 28.7
 77.2
Accounts receivable, net of allowance for credit losses of $2.3 and $2.8, respectively (Note 2)Accounts receivable, net of allowance for credit losses of $2.3 and $2.8, respectively (Note 2)63.7 69.7 
InventoriesInventories9.1 8.8 
Taxes applicable to subsequent years 19.6
 81.0
Taxes applicable to subsequent years58.0 78.0 
Regulatory assets, current 4.5
 0.1
Regulatory assets, current35.1 27.5 
Other prepayments and current assets 23.4
 31.8
Assets held for sale - current (Note 13) 57.0
 —
Taxes receivableTaxes receivable20.1 17.9 
Prepayments and other current assetsPrepayments and other current assets7.3 5.8 
Total current assets 270.0
 408.8
Total current assets227.5 233.2 
    
Property, plant & equipment:    Property, plant & equipment:  
Property, plant & equipment 1,963.5
 1,985.6
Property, plant & equipment1,873.8 1,839.3 
Less: Accumulated depreciation and amortization (372.6) (334.8)Less: Accumulated depreciation and amortization(429.5)(415.7)
 1,590.9
 1,650.8
 1,444.3 1,423.6 
Construction work in process 70.8
 116.4
Construction work in process145.5 141.7 
Total net property, plant & equipment 1,661.7
 1,767.2
Total net property, plant & equipment1,589.8 1,565.3 
Other non-current assets:    Other non-current assets:  
Regulatory assets, non-current 209.4
 203.9
Regulatory assets, non-current191.9 193.6 
Intangible assets, net of amortization 19.7
 22.7
Intangible assets, net of amortization17.4 19.3 
Other deferred assets 13.5
 16.6
Other non-current assetsOther non-current assets26.9 24.6 
Total other non-current assets 242.6
 243.2
Total other non-current assets236.2 237.5 
    
Total assets $2,174.3
 $2,419.2
Total assets$2,053.5 $2,036.0 
    
LIABILITIES AND SHAREHOLDER'S DEFICIT    LIABILITIES AND SHAREHOLDER'S DEFICIT
Current liabilities:    Current liabilities:
Current portion of long-term debt (Note 7) $29.7
 $29.7
Short-term debt 65.0
 —
Short-term and current portion of long-term debt (Note 6)Short-term and current portion of long-term debt (Note 6)$160.2 $100.2 
Accounts payable 61.3
 113.9
Accounts payable67.5 84.5 
Accrued taxes 169.9
 185.1
Accrued taxes84.2 83.0 
Accrued interest 26.8
 17.7
Accrued interest18.4 16.0 
Security deposits 16.4
 15.2
Customer depositsCustomer deposits24.4 19.4 
Regulatory liabilities, current 20.0
 33.7
Regulatory liabilities, current21.6 18.0 
Insurance and claims costs 5.4
 5.4
Other current liabilities 31.5
 50.2
Liabilities held for sale - current (Note 13) 7.0
 —
Accrued and other current liabilitiesAccrued and other current liabilities18.3 21.0 
Total current liabilities 433.0
 450.9
Total current liabilities394.6 342.1 
    
Non-current liabilities:    Non-current liabilities:
Long-term debt (Note 7) 1,712.2
 1,828.7
Deferred taxes 254.6
 252.4
Long-term debt (Note 6)Long-term debt (Note 6)1,393.8 1,393.4 
Deferred income taxesDeferred income taxes182.8 177.2 
Taxes payable 3.6
 84.6
Taxes payable41.1 80.4 
Regulatory liabilities, non-current 134.5
 130.4
Regulatory liabilities, non-current214.4 218.3 
Pension, retiree and other benefits 100.7
 101.6
Asset retirement obligations 132.5
 138.8
Other deferred credits 14.0
 19.4
Accrued pension and other post-retirement benefitsAccrued pension and other post-retirement benefits83.4 93.9 
Other non-current liabilitiesOther non-current liabilities13.0 14.2 
Total non-current liabilities 2,352.1
 2,555.9
Total non-current liabilities1,928.5 1,977.4 
    
Commitments and contingencies (Note 10) 
 
Commitments and contingencies (Note 9)Commitments and contingencies (Note 9)00
    
Common shareholder's deficit    Common shareholder's deficit
Common stock:    Common stock:
1,500 shares authorized; 1 share issued and outstanding at September 30, 2017 and December 31, 2016 —
 —
1,500 shares authorized; 1 share issued and outstanding1,500 shares authorized; 1 share issued and outstanding0 0 
Other paid-in capital 2,233.3
 2,233.0
Other paid-in capital2,468.8 2,468.8 
Accumulated other comprehensive income 6.1
 0.3
Accumulated other comprehensive lossAccumulated other comprehensive loss(12.0)(12.3)
Accumulated deficit (2,850.2) (2,820.9)Accumulated deficit(2,726.4)(2,740.0)
Total common shareholder's deficit (610.8) (587.6)Total common shareholder's deficit(269.6)(283.5)
    
Total liabilities and shareholder's deficit $2,174.3
 $2,419.2
Total liabilities and shareholder's deficit$2,053.5 $2,036.0 
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.


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DPL INC.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
Three months ended March 31,
$ in millions20212020
Cash flows from operating activities:
Net income$13.6 $1.9 
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization19.1 17.8 
Deferred income taxes3.5 3.4 
Changes in certain assets and liabilities:
Accounts receivable, net6.0 14.2 
Inventories(0.3)3.4 
Taxes applicable to subsequent years20.0 17.0 
Deferred regulatory costs, net(4.8)(5.0)
Accounts payable(1.6)(7.6)
Accrued taxes payable / receivable(40.2)(39.2)
Accrued interest2.4 15.1 
Accrued pension and other post-retirement benefits(10.5)(8.2)
Other(1.7)(0.4)
Net cash provided by operating activities5.5 12.4 
Cash flows from investing activities:
Capital expenditures(51.9)(40.2)
Cost of removal payments(4.5)(4.4)
Payments on disposal and sale of business interests(0.4)0 
Proceeds from sale of property (a)
0 5.1 
Other investing activities, net0 (0.7)
Net cash used in investing activities(56.8)(40.2)
Cash flows from financing activities:
Borrowings from revolving credit facilities60.0 45.0 
Repayment of borrowings from revolving credit facilities0 (10.0)
Net cash provided by financing activities60.0 35.0 
Cash, cash equivalents, and restricted cash:
Net change8.7 7.2 
Balance at beginning of period25.5 47.0 
Cash, cash equivalents, and restricted cash at end of period$34.2 $54.2 
Supplemental cash flow information:
Interest paid, net of amounts capitalized$12.9 $2.3 
Non-cash financing and investing activities:
Accruals for capital expenditures$16.3 $5.0 

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
  Nine months ended September 30,
$ in millions 2017 2016
Cash flows from operating activities:    
Net loss $(29.3) $(89.9)
Adjustments to reconcile net loss to net cash from operating activities:    
Depreciation and amortization 81.8
 100.3
Charge for early redemption of debt 3.3
 3.1
Deferred income taxes (3.5) (101.4)
Fixed-asset impairment 66.4
 235.5
Gain on sale of business —
 (49.2)
Loss on asset disposal 15.9
 0.1
Changes in certain assets and liabilities:    
Accounts receivable 15.8
 23.6
Inventories 9.5
 29.1
Prepaid taxes —
 0.2
Taxes applicable to subsequent years 61.4
 61.5
Deferred regulatory costs, net (6.5) 19.5
Accounts payable (46.4) (10.2)
Accrued taxes payable (93.5) (34.2)
Accrued interest payable 8.8
 13.9
Security deposits 1.1
 (0.6)
Pension, retiree and other benefits 3.8
 (2.2)
Other (6.9) (0.5)
Net cash provided by operating activities 81.7
 198.6
Cash flows from investing activities:    
Capital expenditures (95.6) (109.8)
Proceeds from sale of business —
 75.5
Insurance proceeds 12.6
 5.2
Purchase of renewable energy credits (0.1) (0.3)
Decrease in restricted cash 27.0
 5.5
Other investing activities, net 0.3
 0.8
Net cash used in investing activities (55.8) (23.1)
Cash flows from financing activities:    
Payments of deferred financing costs —
 (8.0)
Issuance of long-term debt, net of discount —
 442.8
Retirement of long-term debt (122.1) (520.8)
Borrowings from revolving credit facilities 80.0
 —
Repayment of borrowings from revolving credit facilities (15.0) —
Other financing activities, net —
 (0.1)
Net cash used in financing activities (57.1) (86.1)
Cash and cash equivalents:    
Net change (31.2) 89.4
Balance at beginning of period 54.6
 32.4
Cash and cash equivalents at end of period $23.4
 $121.8
Supplemental cash flow information:    
Interest paid, net of amounts capitalized $69.0
 $61.1
Income taxes paid / (refunded), net $—
 $0.3
Non-cash financing and investing activities:    
Accruals for capital expenditures $9.2
 $15.9
(a)    Proceeds from sale of property include $5.1 million of proceeds received from AES during the three months ended March 31, 2020 related to the 2019 sale of software previously recorded on AES Ohio Generation. There was no gain or loss recorded on the transaction.


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



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DPL INC.
Condensed Consolidated Statements of Shareholder's Deficit
(Unaudited)

Common Stock (a)
$ in millionsOutstanding SharesAmountOther
Paid-in
Capital		Accumulated Other Comprehensive LossAccumulated DeficitTotal
Balance, January 1, 20211 $0 $2,468.8 $(12.3)$(2,740.0)$(283.5)
Net comprehensive income0.3 13.6 13.9 
Balance, March 31, 20211 $0 $2,468.8 $(12.0)$(2,726.4)$(269.6)

(a)    1,500 shares authorized.

Common Stock (a)
$ in millionsOutstanding SharesAmountOther
Paid-in
Capital		Accumulated Other Comprehensive LossAccumulated DeficitTotal
Balance, January 1, 20201 $0 $2,370.7 $(3.6)$(2,739.0)$(371.9)
Net comprehensive income(0.3)1.9 1.6 
Balance, March 31, 20201 $0 $2,370.7 $(3.9)$(2,737.1)$(370.3)

(a)1,500 shares authorized.

See Notes to Condensed Consolidated Financial Statements.

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DPL Inc.
Notes to Unaudited Condensed Consolidated Financial Statements (Unaudited)


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 has two1 reportable segments:segment: the Transmission and Distribution segment and the GenerationUtility segment. See Note 1110 – Business Segments for more information relating to thesethis reportable segments.segment. The terms “we,” “us,” “our” and “ours” are used to refer to DPL and its subsidiaries.


DPL is an indirectly wholly-owned subsidiary of AES.


DP&L, a wholly-owned subsidiary of DPL that does business as AES Ohio, 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, retail transmission and distribution services are still regulated. DP&LAES Ohio has the exclusive right to provide such transmission and distribution services to approximately 520,000532,000 customers located in West Central Ohio. Additionally, DP&L procuresAES Ohio provides retail SSO electric service on behalf ofto residential, commercial, industrial and governmental customers in a 6,000 square6,000-square mile area of West Central Ohio. As of September 30, 2017, DP&L owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. As of October 1, 2017, the DP&L-owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL, through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Also, Stuart Station Unit 1 was retired on October 1, 2017. DP&L sources 100%all of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’sAES Ohio’s service territory include automotive, food processing, paper, plastic, health care, data management, manufacturing and defense. DP&L's distributionAES Ohio's sales reflect the general economic conditions, seasonal weather patterns of the proliferation of energy efficiency and distributed renewable resourcesarea and the market price of electricity. From January 1, 2016 through September 30, 2017, DP&LAES Ohio owned interests in the retired Hutchings Coal Station until its transfer in 2020, and currently owns numerous transmission facilities. AES Ohio sells its proportional share of energy and capacity from its investment in OVEC into the wholesale market.

DPL’s other primary subsidiaries are MVIC and Miami Valley Lighting. MVIC is our captive insurance company that provides insurance services to AES Ohio and our other subsidiaries, and Miami Valley Lighting provides street and outdoor lighting services to customers in the Dayton region. In prior periods, AES Ohio Generation was also a primary subsidiary and sold all of its energy and capacity into the wholesale market.

DPL’s other significant subsidiaries include In 2020, AES Ohio GenerationGeneration's only operating asset was an undivided interest in Conesville, which closed in May 2020 and MVIC, our captive insurance company that provides insurance services to DPL and our subsidiaries. AES Ohio Generation, as of September 30, 2017, owned and operated certain peaking generating facilities, and, as of October 1, 2017, owns those facilities plus additional coal-fired and peaking facilities previously owned by DP&L. AES Ohio Generation sellswas sold in June 2020. See Note 12 – Discontinued Operations for more information. DPL's subsidiaries are all of its energy and capacity into the wholesale market. DPL owns all of the common stock of its subsidiaries.wholly-owned.


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


DP&L’sAES Ohio’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&LAES Ohio 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.costs or overcollections of riders.

DPL and its subsidiaries employed 1,074 people as of September 30, 2017, of which 1,065 were employed by DP&L. As part of Generation Separation on October 1, 2017, DP&L generation employees became employees of AES Ohio Generation. Approximately 61% of all DP&L and AES Ohio Generation employees are under a collective bargaining agreement that was set to expire on October 31, 2017. The Company and the union representing these employees have agreed to extend the current agreement through January 31, 2018, while continuing to negotiate a new agreement. We are unable to determine what impact a new agreement may have on our operations.


Financial Statement Presentation
DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II, which is not consolidated, consistent with the provisions of GAAP. As of September 30, 2017, DP&L had undivided ownership interests in five coal-fired generating facilities, various peaking generating facilities and numerous transmission facilities, all of which are included in the financial statements at the lower of depreciated historical cost or fair value, if impaired. Operating revenues and expenses of


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these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statements of Operations.


Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation.


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


These financial statements have been prepared in accordance with GAAP, as contained in the FASB ASC, for interim financial statements and Article 10 of Regulation S-X issued by the instructions of Form 10-Q and Regulation S-X.SEC. Accordingly, certainthey do not include all the information and footnote disclosures normally included in thefootnotes required by GAAP for annual financial statements prepared in accordance with GAAP have been omitted from this interim report.fiscal reporting periods. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2016.2020.


In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of September 30, 2017;March 31, 2021; our results of operations
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for the three and nine months ended September 30, 2017March 31, 2021 and 2016 and2020, our cash flows for the ninethree months ended September 30, 2017March 31, 2021 and 2016.2020 and the changes in our equity for the three months ended March 31, 2021 and 2020. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2017March 31, 2021 may not be indicative of our results that will be realized for the full year ending December 31, 2017.2021.


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: recognition of revenue including unbilled revenues, 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 receivablescredit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.


Cash, Cash Equivalents and Restricted Cash
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Condensed Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Condensed Consolidated Statements of Cash Flows:
$ in millionsMarch 31, 2021December 31, 2020
Cash and cash equivalents$34.1 $25.4 
Restricted cash0.1 0.1 
Cash, Cash Equivalents, and Restricted Cash, End of Period$34.2 $25.5 

Inventories
Inventories consist of materials and supplies at March 31, 2021 and December 31, 2020.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&LAES Ohio collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended September 30, 2017March 31, 2021 and 20162020 were $13.0$12.9 million and $14.4$12.4 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2017 and 2016 were $36.9 million and $38.9 million, respectively.


New Accounting Pronouncements
Issued But Not Yet Effective – The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements:
statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our consolidated financial statements.
Accounting StandardASU Number and NameDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation2020-04, Reference Rate Form (Topic 718)848): Improvements to Employee Share-Based Payment AccountingFacilitation of the Effects of Reference Rate Reform on Financial ReportingThe standard simplifies the following aspects of accountingprovides optional expedients and exceptions for share-based payments 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 equityapplying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR 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 recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis.		January 1, 2017.The primary effect of adoption was 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. The adoption of this standard did not have a material impact on the consolidated financial statements.


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Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities
The standard updates the hedge accounting model in ASC 815 to expand the ability to hedge risk, reduce complexity and ease certain documentation and assessment requirements. It also eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrumentanother reference rate expected to be presented in the same income statement line as the hedged item.
Transition method: modified retrospective approach and prospectivediscontinued by reference rate reform. This standard is effective for presentation and disclosures.
a limited period of time (March 12, 2020 - December 21, 2022).		January 1, 2019.
Early adoption is permitted.Effective for all entities March 12, 2020 - December 31, 2022		We are currently evaluating the impact of adopting the standard on our consolidated financial statements and if we would early adopt it.
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt SecuritiesThis standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date.
Transition method: modified retrospective.		January 1, 2019.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on ourcondensed consolidated financial statements.
2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit CostThis standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization.
Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in capitalization.
January 1, 2018.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of businesses is under scope of ASC 810.
Transition method: full or modified retrospective we are in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of the balance sheet date, the contracts that may require any type of assessment under the new standard are limited.		January 1, 2018.We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We will adopt the standard on January 1, 2018 and plan to use the modified retrospective approach.
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.
Transition method: prospective.		January 1, 2018.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2016-18, Statement of Cash Flows (Topic 230): 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.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than InventoryThis standard requires that an entity recognize 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.
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial InstrumentsThis 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.



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Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
2016-02, Leases (Topic 842)This standard requires lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions.
Transition method: modified retrospective at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).

We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.		January 1, 2019.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on our consolidated financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606)See discussion of the ASUs below.January 1, 2018.We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP.

In 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. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

Given the complexity and diversity of our non-regulated arrangements, we are assessing the standard on a contract-by-contract basis and are in the process of completing the contract assessments by applying interpretations reached during 2017 on key issues. These issues include the application of the practical expedient for measuring progress towards 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 allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. We will continue our work to complete the assessment of the full population of contracts and determine the overall impact to the consolidated financial statements.

The standard requires retrospective application and allows either a full retrospective adoption in which all periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. Although we had previously been working toward adopting the standard using the full retrospective method, given the limited situations where revenue recognized under ASC 606 differs from that recognized under ASC 605, we now expect to use the modified retrospective approach. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.



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Note 2 – Supplemental Financial Information


Accounts receivable and Inventories are as follows at September 30, 2017March 31, 2021 and December 31, 2016:2020:
March 31,December 31,
$ in millions20212020
Accounts receivable, net:
Customer receivables$45.7 $48.5 
Unbilled revenue15.5 21.6 
Amounts due from affiliates0.5 0.2 
Due from PJM transmission enhancement settlement1.7 1.7 
Other2.6 0.5 
Allowance for credit losses(2.3)(2.8)
Total accounts receivable, net$63.7 $69.7 

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  September 30, December 31,
$ in millions 2017 2016
Accounts receivable, net:    
Unbilled revenue
$14.4
 $43.0
Customer receivables 74.2
 73.9
Amounts due from partners in jointly-owned plants 17.8
 12.7
Other 6.1
 6.7
Provision for uncollectible accounts (1.1) (1.2)
Total accounts receivable, net $111.4
 $135.1
     
Inventories, at average cost:    
Fuel and limestone $16.8
 $38.9
Plant materials and supplies 10.9
 36.6
Other 1.0
 1.7
Total inventories, at average cost $28.7
 $77.2
The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the three months ended March 31, 2021 and 2020 :

$ in millionsBeginning Allowance BalanceCurrent Period ProvisionWrite-offs Charged Against AllowancesRecoveries CollectedEnding Allowance Balance
2021$2.8 $0 $(0.7)$0.2 $2.3 
2020$0.4 $0.4 $(0.4)$0.3 $0.7 

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, including the economic impacts of the COVID-19 pandemic on our receivable balance as of March 31, 2021. Amounts are written off when reasonable collections efforts have been exhausted. During 2021, the current period provision and allowance for credit losses have decreased due to lower past due customer receivable balances. See Note 13 – Risks and Uncertainties for additional discussion of the COVID-19 pandemic.

Accumulated Other Comprehensive Income / (Loss)other comprehensive loss
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss)other comprehensive loss by component during the three and nine months ended September 30, 2017March 31, 2021 and 20162020 are as follows:
Details about Accumulated Other Comprehensive Loss componentsAffected line item in the Condensed Consolidated Statements of OperationsThree months ended
March 31,
$ in millions20212020
Gains and losses on cash flow hedges (Note 5):
Interest expense$(0.2)$(0.4)
Income tax expense0 0.1 
Net of income taxes(0.2)(0.3)
Amortization of defined benefit pension items (Note 8):
Other expense0.6 0.3 
Income tax benefit(0.1)0 
Net of income taxes0.5 0.3 
Total reclassifications for the period, net of income taxes$0.3 $0 
Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Consolidated Statements of Operations Three months ended Nine months ended
    September 30, September 30,
$ in millions   2017 2016 2017 2016
Gains and losses on Available-for-sale securities activity (Note 5):
  Other income $—
 $—
 $(0.1) $—
           
Gains and losses on cash flow hedges (Note 6):        
  Interest expense (0.2) (0.2) (0.8) (0.7)
  Revenue (4.2) (9.3) (12.5) (46.6)
  Purchased power 0.7
 1.0
 4.0
 9.1
  Total before income taxes (3.7) (8.5) (9.3) (38.2)
  Tax expense 1.3
 3.0
 3.3
 13.8
  Net of income taxes (2.4) (5.5) (6.0) (24.4)
           
Amortization of defined benefit pension items (Note 9):        
  Operation and maintenance —
 —
 1.4
 0.2
  Tax benefit —
 —
 (0.5) (0.1)
  Net of income taxes —
 —
 0.9
 0.1
           
Total reclassifications for the period, net of income taxes $(2.4) $(5.5) $(5.2) $(24.3)




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The changes in the components of Accumulated Other Comprehensive Income / (Loss)other comprehensive loss during the ninethree months ended September 30, 2017March 31, 2021 are as follows:
$ in millionsGains / (losses) on cash flow hedgesChange in unfunded pension and postretirement benefit obligationsTotal
Balance at January 1, 2021$13.6 $(25.9)$(12.3)
Amounts reclassified from AOCL to earnings(0.2)0.5 0.3 
Net current period other comprehensive income / (loss)(0.2)0.5 0.3 
Balance at March 31, 2021$13.4 $(25.4)$(12.0)

17
$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance at January 1, 2017 $0.6
 $13.1
 $(13.4) $0.3
         
Other comprehensive income / (loss) before reclassifications 0.4
 12.1
 (1.5) 11.0
Amounts reclassified from accumulated other comprehensive income / (loss) (0.1) (6.0) 0.9
 (5.2)
Net current period other comprehensive income / (loss) 0.3
 6.1
 (0.6) 5.8
         
Balance at September 30, 2017 $0.9
 $19.2
 $(14.0) $6.1

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Note 3 – Regulatory Matters


In January 2017, DP&L filedESP and SEET Proceedings
On October 23, 2020, AES Ohio entered into a Stipulation and Recommendation (settlement) with the staff of the PUCO and various customers, and organizations representing customers of AES Ohio and certain other parties with respect to, among other matters, AES Ohio's applications pending at the PUCO for (i) approval of AES Ohio's plan to modernize its distribution grid (the Smart Grid Plan), (ii) findings that AES Ohio passed the SEET for 2018 and 2019, and (iii) findings that AES Ohio's current ESP 1 satisfies the SEET and the more favorable in the aggregate (MFA) regulatory test. The settlement in its ESP 3 case and filed an amended stipulation on March 13, 2017, which wasis subject to, and conditioned upon, approval by the PUCO. A final decisionhearing was issuedheld in January 2021 for consideration of this settlement; a commission order is pending.

Decoupling
On January 23, 2020 AES Ohio filed with the PUCO requesting approval to defer its decoupling costs consistent with the methodology approved in its Distribution Rate Case. If approved, deferral would be effective December 18, 2019 and going forward would reduce impacts of weather, energy efficiency programs and economic changes in customer demand. An evidentiary hearing was held on this matter on May 4, 2021.

Distribution Rate Case
On November 30, 2020, AES Ohio filed a new Distribution Rate Case with the PUCO. This rate case proposes a revenue increase of $120.8 million per year and incorporates the DIR investments that were planned and approved in the last rate case but not yet included in distribution rates, other distribution investments since September 2015 and investments necessitated by the PUCOtornados that occurred on October 20, 2017, modifyingMemorial Day in 2019. The rate case also includes a proposal for increased tree-trimming expenses and adoptingcertain customer demand-side management programs and recovery of prior-approved regulatory assets for tree trimming, uncollectible expenses and rate case expense. This case is pending a commission order.

FERC Proceedings
On November 15, 2018 the amended stipulationFERC issued a Notice of Proposed Rulemaking (NOPR) to address amortization of excess accumulated deferred income taxes resulting from the TCJA and recommendation. The ESP establishes DP&L's framework for providing retail servicetheir impact on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory parties agreedtransmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;
The establishment of a three-year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 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. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;
The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments,determine the amount of which is to be established in a separate DP&L distribution rate case
A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs;
Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order to be effective November 1, 2017;
A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L; and
Restrictions on DPL making dividend or tax sharing payments; and
Various other riders and competitive retail market enhancements.

In connection with any sale or closure of our generation plants as contemplatedexcess deferred income taxes caused by the ESPTCJA. On March 3, settlement or otherwise, DPL and DP&L would expect2020, AES Ohio filed an application before the FERC to incur certain cash and non-cash charges, some or all ofchange its transmission rate from a stated rate to a formula rate, which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approvedwas accepted by the PUCO forFERC and made effective as of May 3, 2020, subject to further proceeding and potential refunds. An uncontested settlement was filed December 10, 2020, which would increase the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion statedrates that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with thosewere in effect prior to 2014.the filing but are a reduction from the rate that became effective subject to refund on May 3, 2020. Among other things, the settlement establishes new depreciation rates for our transmission assets and an authorized return on equity (ROE) of 9.85%, which would rise to 9.99% if the FERC were to approve in a separate ongoing proceeding a return on equity “adder” to recognize our continued membership in PJM. The PUCO approved DP&L’s withdrawal of ESP 29.85% ROE (base) and implementation plans. Those rates were in effect until rates approved as a result of DP&L’s pending ESP 39.99% ROE (base + incentive) levels are effective, November 1, 2017. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending, and the outcome and potential financial impact of those appeals cannot be determined


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at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending. That stay was denied by the Ohio Supreme Court in September 2017.

DP&L is subject to a SEET thresholdfour-year moratorium on other proposed ROE changes. Proposals to raise or lower the ROE could be filed with an effective date after the moratorium expires on April 14, 2025. The required flowback of excess deferred taxes under the NOPR was also addressed and is requiredresolved as part of this formula transmission rate settlement. On April 15, 2021, the FERC approved the transmission rate settlement.

Note 4 – Fair Value

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair values of our assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions 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 ESP 3 maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded fromsell assets or transfer liabilities, the SEET calculation. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending. In future years, the SEET coulduse of different market assumptions and/or estimation methodologies may have a material effect on resultsthe estimated fair value amounts. For further information on our valuation techniques and policies, see Note 5—Fair Value in Item 8. — Financial Statements and Supplementary Data of operations, financial condition and cash flows.our Form 10-K.

Note 4 – Property, Plant and Equipment

Coal-fired facilities
As of September 30, 2017, DP&L and certain other Ohio utilities had 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. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed Consolidated 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 Condensed Consolidated Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each co-owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

DP&L’s undivided ownership interest in such facilities at September 30, 2017, was as follows:
18
  
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)
Jointly-owned production units          
Conesville - Unit 4 16.5 129
 $0.5
 $0.5
 $2.3
Killen - Unit 2 67.0 402
 8.5
 4.1
 —
Miami Fort - Units 7 and 8 (a) 36.0 368
 31.3
 3.3
 5.1
Stuart - Units 2 through 4 35.0 606
 0.7
 0.7
 —
Zimmer - Unit 1 (a) 28.1 371
 21.3
 15.3
 5.2
Transmission (at varying percentages)     43.2
 11.5
 —
Total   1,876
 $105.5
 $35.4
 $12.6

(a)
DP&L has entered into an agreement to sell its interest in these units. See Note 13 – Assets and Liabilities Held for Sale for additional information.

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

On January 10, 2017, a high-pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries, which was recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. This unit was retired on October 1, 2017. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the DP&L operated and co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement.



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On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the fourth quarter of 2017. See Note 13 – Assets and Liabilities Held for Sale for additional information.

On October 1, 2017, Generation Separation was completed and the coal-fired electric generating facilities described above were transferred to AES Ohio Generation. The portion of the co-owned transmission facilities owned by DP&L remains owned by DP&L.

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.

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 January 1, 2017$138.8
Additions0.1
Revisions to cash flow and timing estimates(4.8)
Accretion expense2.9
Settlements(0.1)
Reclassified to Liabilities held for sale(4.4)
Balance at September 30, 2017$132.5

See Note 5 – Fair Value for further discussion on changes to our AROs.

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



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The following table presents the fair value, carrying value and cost of our non-derivative instruments at September 30, 2017March 31, 2021 and December 31, 2016. Information2020. Further information about the fair value of our derivative instruments can be found in Note 65 – Derivative Instruments and Hedging Activities.
March 31, 2021December 31, 2020
$ in millionsCostFair ValueCostFair Value
Assets
Money market funds$0.2 $0.2 $0.3 $0.3 
Equity securities2.0 4.7 2.1 4.5 
Debt securities3.8 3.8 4.0 4.1 
Total Assets$6.0 $8.7 $6.4 $8.9 
Carrying ValueFair ValueCarrying ValueFair Value
Liabilities
Long-term debt$1,394.0 $1,487.0 $1,393.6 $1,571.6 
  September 30, 2017 December 31, 2016
$ in millions Cost Fair Value Cost Fair Value
Assets        
Money market funds $0.4
 $0.4
 $0.4
 $0.4
Equity securities 2.6
 4.1
 2.4
 3.4
Debt securities 4.2
 4.3
 4.4
 4.4
Hedge funds 0.1
 0.1
 —
 0.1
Real estate —
 —
 0.3
 0.3
Tangible assets 0.1
 0.1
 0.1
 0.1
Total Assets $7.4
 $9.0
 $7.6
 $8.7
         
  Carrying Value Fair Value Carrying Value Fair Value
Liabilities        
Long-term debt (a) $1,741.6
 $1,843.8
 $1,858.0
 $1,907.7

(a)Amounts exclude immaterial capital lease obligations


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

Fair Value Hierarchy
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
Level 1 (quoted prices in active markets for identical assets or liabilities);
Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or
Level 3 (unobservable inputs) 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, Level 2 or Level 3 of the fair value hierarchy during the ninethree months ended September 30, 2017March 31, 2021 or 2016.2020.


Master Trust Assets
DP&LAES Ohio established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferrednon-current assets on the balance sheetsCondensed Consolidated Balance Sheets and classified as available-for-sale. Anyequity investments. We recorded net unrealized gains or losses are recorded in AOCI until/ (losses) of $0.2 million and $(1.1) million during the securities are sold.

DPL had $1.5 million ($0.9 million after tax) of unrealized gains and immaterial unrealized losses onduring the Master Trust assets in AOCI at September 30, 2017 and $1.0 million ($0.6 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2016.

During the ninethree months ended September 30, 2017, $0.8 million ($0.6 million after tax)March 31, 2021 and 2020, respectively. These amounts are included in "Other income / (expense)" in our Condensed Consolidated Statements of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterialOperations.


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amount of unrealized gains are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distribution of benefits.


Long-term 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 long-term debt is presented at cost,carrying value, net of unamortized premium or discount and unamortized deferred financing costs in the financial statements. The long-term debt amounts include the current portion payable in the next twelve months and have maturities that range from 20192025 to 2061.


The fair value of assets and liabilities at September 30, 2017March 31, 2021 and December 31, 20162020 and the respective category within the fair value hierarchy for DPL was determined is as follows:
$ in millionsFair value at March 31, 2021 (a)Fair value at December 31, 2020 (a)
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Master Trust assets
Money market funds$0.2 $0 $0 $0.2 $0.3 $0 $0 $0.3 
Equity securities0 4.7 0 4.7 0 4.5 0 4.5 
Debt securities0 3.8 0 3.8 0 4.1 0 4.1 
Total Master Trust assets0.2 8.5 0 8.7 0.3 8.6 0 8.9 
Total Assets$0.2 $8.5 $0 $8.7 $0.3 $8.6 $0 $8.9 
Liabilities
Long-term debt$0 $1,469.7 $17.3 $1,487.0 $0 $1,554.2 $17.4 $1,571.6 
Total Liabilities$0 $1,469.7 $17.3 $1,487.0 $0 $1,554.2 $17.4 $1,571.6 

(a)    Includes credit valuation adjustment

19
Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair value at September 30, 2017 (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 4.1
 —
 4.1
 —
Debt securities 4.3
 —
 4.3
 —
Hedge funds 0.1
 —
 0.1
 —
Tangible assets 0.1
 —
 0.1
 —
Total Master Trust assets 9.0
 0.4
 8.6
 —
Derivative Assets        
Forward power contracts 10.8
 —
 10.8
 —
Interest rate hedges 0.9
 —
 0.9
 —
Natural gas —
 —
 —
 —
Total Derivative assets 11.7
 —
 11.7
 —
         
Total Assets $20.7
 $0.4
 $20.3
 $—
         
Liabilities        
Derivative Liabilities        
Interest rate hedges $—
 $—
 $—
 $—
FTRs 0.5
 —
 —
 0.5
Natural gas futures 0.8
 0.8
 —
 —
Forward power contracts 8.1
 —
 8.1
 —
Total Derivative liabilities 9.4
 0.8
 8.1
 0.5
Long-term debt (b) 1,843.8
 —
 1,825.9
 17.9
         
Total Liabilities $1,853.2
 $0.8
 $1,834.0
 $18.4

(a)Includes credit valuation adjustment
(b)Amounts exclude immaterial capital lease obligations


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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 hedges 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        
Derivative liabilities        
Interest rate hedges $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 (b) 1,907.7
 —
 1,889.7
 18.0
         
Total Liabilities $1,936.9
 $—
 $1,916.4
 $20.5

(a)Includes credit valuation adjustment
(b)Amounts exclude immaterial capital lease obligations

Our financial instruments are valued using the market approach in the following categories:
Level 1 inputs are used for derivative contracts such as natural gas 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 in the Master Trust, which are valued using the end of day NAV per unit.
Level 3 inputs such as FTRs are considered a Level 3 input because the monthly auctions are considered inactive. Other Level 3 inputs include the credit valuation adjustment on some of the forward power contracts and forward power contracts in less active markets. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.
Approximately 86%All of the inputs to the fair value of our derivative instruments are from quoted market prices.


Our long-term 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. As the Wright-Patterson Air Force Base note is not publicly traded, fair value is assumed to equal carrying value. Thesethe fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures are not presented since our long-term debt is not recorded at fair value.




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Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.8 million in the first nine months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $1.9 million and increased by a net amount of $3.0 million during the nine months ended September 30, 2017 and 2016, respectively. In addition, there was a $4.4 million decrease in the ARO liability during the nine months ended September 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018, and the co-owners of the Facilities agreed with DP&L to proceed with this plan of retirement. As a result, we performed a long-lived asset impairment analysis during the first quarter of 2017 and determined that the carrying amounts of the Facilities were not recoverable. See Note 14 – Fixed-asset Impairments.

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 Killen and certain DP&L peaking generating facilities. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and determined that the carrying amount of these assets were not recoverable. See Note 14 – Fixed-asset Impairments.

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 Long-lived assets measured at fair value on a non-recurring basis during the periods and their level within the fair value hierarchy:
  Carrying Fair Value Gross
  
Amount (b)
 Level 1 Level 2 Level 3 Loss
$ in millions Nine months ended September 30, 2017
Assets          
Long-lived assets (a)
          
Stuart $42.4
 $—
 $—
 $3.3
 $39.1
Killen $35.2
 $—
 $—
 $7.9
 $27.3
          $66.4
           
  Nine months ended September 30, 2016
Assets          
Long-lived assets (a)
          
Killen $315.1
 $—
 $—
 $84.3
 $230.8
DP&L peaking facilities
 $9.9
 $—
 $—
 $5.2
 $4.7
          $235.5

(a)See Note 14 – Fixed-asset Impairments for further information
(b)Carrying amount at date of valuation



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The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the nine months ended September 30, 2017:
$ in millions Fair value Valuation technique Unobservable input Weighted average
Long-lived assets held and used:
Stuart $3.3
 Discounted cash flow Pre-tax operating margin
(through remaining life)		 10.0%
      Weighted-average cost of capital 7.0%
         
Killen $7.9
 Discounted cash flow Pre-tax operating margin
(through remaining life)		 22.0%
      Weighted-average cost of capital 7.0%
The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the nine months ended September 30, 2016:
$ in millions Fair value Valuation technique Unobservable input Weighted average
Long-lived assets held and used:
Killen $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%
         
DP&L peaking facilities
 $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%

Note 65 – 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 ofFor further information on our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 forhedge accounting purposes.policies, See Note 1 – Overview and Summary of Significant Accounting Policies – Financial Derivatives and Note 6 - Derivative Instruments and Hedging Activities of Item 8 – Financial Statements and Supplementary Data in our Form 10-K.

At September 30, 2017, DPL's derivative instruments were as follows:
Commodity 
Accounting Treatment (a)
 Unit Purchases
(in thousands)		 Sales
(in thousands)		 Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 3.4
 —
 3.4
Natural gas futures Not designated Dths 6,625.0
 (390.0) 6,235.0
Forward power contracts Designated MWh 649.0
 (2,478.9) (1,829.9)
Forward power contracts Not designated MWh 1,082.8
 (1,060.0) 22.8
Interest rate swaps Designated USD $200,000.0
 $—
 $200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.



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At December 31, 2016, DPL's derivative instruments were as follows:
Commodity 
Accounting Treatment (a)
 Unit Purchases
(in thousands)		 Sales
(in thousands)		 Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 2.3
 —
 2.3
Natural gas futures 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

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.


Cash Flow Hedges
As part of our risk management processes, we identifyIn August 2020, 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 have two2 interest rate swaps to hedge the variable interest on our $200.0the $140.0 million variable interest rate tax-exempt First Mortgage Bonds.Bonds expired, as the associated debt reached maturity. The interest rate swaps havehad a combined notional amount of $200.0$140.0 million and will settlesettled monthly based on a one monthone-month LIBOR. We use the income approach to valueThe AOCL associated with the swaps which consistswas amortized out of forecasting future cash flows based on contractual notional amounts and applicable and available market data asAOCL into interest expense over the life 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.underlying debt.


We also had previously entered into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. These interest rate derivative contracts were settled in the third quarter of 2013 and we continue to amortize amounts out of AOCIAOCL into interest expense.



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The following tables provide information concerning gains or losses recognized in AOCIAOCL for the cash flow hedges for the three and nine months ended September 30, 2017March 31, 2021 and 2016:2020:
Three months ended
March 31, 2021March 31, 2020
InterestInterest
$ in millions (net of tax)Rate HedgeRate Hedge
Beginning accumulated derivative gains in AOCL$13.6 $14.5 
Net losses associated with current period hedging transactions0 (0.3)
Net gains reclassified to earnings
Interest expense(0.2)(0.3)
Ending accumulated derivative gains in AOCL$13.4 $13.9 
Portion expected to be reclassified to earnings in the next twelve months$(0.8)

20
  Three months ended Three months ended
  September 30, 2017 September 30, 2016
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gains in AOCI $3.0
 $17.2
 $3.4
 $17.3
Net gains associated with current period hedging transactions 1.3
 0.1
 9.5
 —
Net gains / (losses) reclassified to earnings      
Interest expense —
 (0.2) —
 (0.1)
Revenues (2.7) —
 (6.0) —
Purchased power 0.5
 —
 0.6
 —
Ending accumulated derivative gains in AOCI $2.1
 $17.1
 $7.5
 $17.2
         
  Nine months ended Nine months ended
  September 30, 2017 September 30, 2016
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI $(4.3) $17.4
 $9.2
 $17.5
Net gains associated with current period hedging transactions 11.9
 0.2
 22.4
 —
Net gains / (losses) reclassified to earnings      
Interest expense —
 (0.5) —
 (0.3)
Revenues (8.1) —
 (30.0) —
Purchased power 2.6
 —
 5.9
 —
Ending accumulated derivative gains in AOCI $2.1
 $17.1
 $7.5
 $17.2
         
Portion expected to be reclassified to earnings in the next twelve months (a)
 $1.5
 $(0.4)    
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 6
 37
    

(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.

Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.

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 purchase and normal sales scope exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty. FTRs, natural gas futures, and certain forward power contracts are currently marked to market.

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


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Financial Statement Effect
The following tables present the amount and classification within the Condensed Consolidated Statements of Operations of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2017 and 2016:
For the three months ended September 30, 2017
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $0.2
 $(1.4) $—
 $(1.2)
Realized gain / (loss) 0.2
 1.9
 (0.2) 1.9
Total $0.4
 $0.5
 $(0.2) $0.7
  
 
 
 
Recorded in Income Statement: gain / (loss) 

 

 

 

Revenues $—
 $3.3
 $—
 $3.3
Purchased power 0.4
 (2.8) (0.2) (2.6)
Total $0.4
 $0.5
 $(0.2) $0.7
         
For the three months ended September 30, 2016
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $—
 $1.2
 $(0.3) $0.9
Realized gain / (loss) (0.1) (2.4) 0.2
 (2.3)
Total $(0.1) $(1.2) $(0.1) $(1.4)
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $(10.4) $—
 $(10.4)
Purchased power (0.1) 9.2
 (0.1) 9.0
Total $(0.1) $(1.2) $(0.1) $(1.4)
         
For the nine months ended September 30, 2017
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $(0.5) $2.3
 $(0.8) $1.0
Realized gain / (loss) 0.5
 (1.4) (0.3) (1.2)
Total $—
 $0.9
 $(1.1) $(0.2)
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $(2.6) $—
 $(2.6)
Purchased power —
 3.5
 (1.1) 2.4
Total $—
 $0.9
 $(1.1) $(0.2)
         
For the nine months ended September 30, 2016
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $0.4
 $2.3
 $—
 $2.7
Realized gain / (loss) (0.4) (5.3) 0.7
 (5.0)
Total $—
 $(3.0) $0.7
 $(2.3)
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $(13.1) $—
 $(13.1)
Purchased power —
 10.1
 0.7
 10.8
Total $—
 $(3.0) $0.7
 $(2.3)
         

DPL has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.


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The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged, as well as the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments:
Fair Values of Derivative Instruments
at September 30, 2017
      Gross Amounts Not Offset in the Condensed 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 Fair Value
Assets          
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts Designated $7.0
 $(4.6) $—
 $2.4
Forward power contracts Not designated 3.5
 (2.7) —
 0.8
Natural gas futures Not designated —
 —
 —
 —
           
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap Designated 0.9
 —
 —
 0.9
Natural gas futures Not designated —
 —
 —
 —
Forward power contracts Not designated 0.3
 —
 —
 0.3
Total assets   $11.7
 $(7.3) $—
 $4.4
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts Designated $4.6
 $(4.6) $—
 $—
Interest rate swap Designated —
 —
 —
 —
Forward power contracts Not designated 3.5
 (2.7) (0.7) 0.1
Natural gas futures Not designated 0.8
 —
 (0.8) —
FTRs Not designated 0.5
 —
 —
 0.5
           
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures Not designated —
 —
 —
 —
Total liabilities   $9.4
 $(7.3) $(1.5) $0.6

(a)    includes credit valuation adjustment


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Fair Values of Derivative Instruments
at December 31, 2016
      Gross Amounts Not Offset in the Condensed 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 Fair Value
Assets          
Short-term derivative positions (presented in Other prepayments and 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
           
Long-term derivative positions (presented in Other deferred credits)
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

Credit risk-related contingent features
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at September 30, 2017 was $9.4 million. $1.5 million of collateral was 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 $7.3 million. Since our long-term debt is below investment grade, we could have to post collateral for the remaining $0.6 million.



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Note 76 – Long-term Debt


The following table summarizes DPL's outstanding long-term debt.
InterestMarch 31,December 31,
$ in millionsRateMaturity20212020
First Mortgage Bonds3.95%2049$425.0 $425.0 
First Mortgage Bonds3.20%2040140.0 140.0 
U.S. Government note4.20%206117.3 17.4 
Unamortized deferred financing costs(5.5)(5.7)
Unamortized debt discounts, net(2.6)(2.6)
Total long-term debt at AES Ohio
574.2 574.1 
Senior unsecured bonds4.125%2025415.0 415.0 
Senior unsecured bonds4.35%2029400.0 400.0 
Note to DPL Capital Trust II (a)8.125%203115.6 15.6 
Unamortized deferred financing costs(9.9)(10.2)
Unamortized debt discounts, net(0.9)(0.9)
Total long-term debt1,394.0 1,393.6 
Less: current portion(0.2)(0.2)
Long-term debt, net of current portion$1,393.8 $1,393.4 
  Interest   September 30, December 31,
$ in millions Rate Maturity 2017 2016
Term loan - rates from 4.01% - 4.49% (a) and 4.00% - 4.01% (b)   2022 $441.7
 $445.0
Tax-exempt First Mortgage Bonds 4.8% 2036 —
 100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.83% (a) and 1.29% - 1.42% (b)   2020 200.0
 200.0
U.S. Government note 4.2% 2061 17.9
 18.0
Capital leases     0.3
 0.4
Unamortized deferred financing costs     (9.9) (10.7)
Unamortized long-term debt discounts and premiums, net     (2.0) (5.5)
Total long-term debt at consolidated subsidiary     648.0
 747.2
         
Bank term loan - rates from 3.02% - 3.99% (a) and 2.67% - 3.02% (b)   2020 106.3
 125.0
Senior unsecured notes 6.75% 2019 200.0
 200.0
Senior unsecured notes 7.25% 2021 780.0
 780.0
Note to DPL Capital Trust II (c) 8.125% 2031 15.6
 15.6
Unamortized deferred financing costs     (7.4) (8.8)
Unamortized long-term debt discounts and premiums, net     (0.6) (0.6)
Total long-term debt     1,741.9
 1,858.4
Less: current portion     (29.7) (29.7)
Long-term debt, net of current portion     $1,712.2
 $1,828.7


(a)Range of interest rates for the nine months ended September 30, 2017.
(b)Range of interest rates for the year ended December 31, 2016.
(c)Note payable to related party.

(a)Note payable to related party.
Deferred financing costs are amortized over the remaining life of the debt using the effective interest method. Premiums or discounts on long-term debt are amortized over the remaining life of the debt using the effective interest method.

LineLines of credit
At September 30, 2017, March 31, 2021 and December 31, 2020, the DPL revolving credit facility had $50.0 million in outstanding borrowings on its line of credit. In addition, DP&L$80.0 million and $80.0 million, respectively. At March 31, 2021 and December 31, 2020, the AES Ohio revolving credit facility had $15.0 million in outstanding borrowings of $80.0 million and $20.0 million, respectively.

DPL’s Senior Unsecured Bonds
DPL agreed to register the 2025 DPL Senior Unsecured Bonds under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC pursuant to a Registration Rights Agreement dated June 19, 2020. DPL filed a registration statement on its line of credit.Form S-4 with respect to the 2025 DPL Senior Unsecured Bonds with the SEC on March 15, 2021, and this registration statement was declared effective on March 31, 2021. The exchange offer was closed on May 5, 2021.

Significant transactions
On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of defeased bonds was completed on October 30, 2017.


Long-term debt covenants and restrictions
DP&L’sDPL’s revolving credit agreement has 2 financial covenants. The first financial covenant, a minimum EBITDA, calculated at the end of each fiscal quarter for the four prior fiscal quarters, of $125.0 million is required, stepping up to $130.0 million on September 30, 2022 and $150.0 million on December 31, 2022. As of March 31, 2021, DPL was in compliance with this financial covenant.

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 4 prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreement, is to be not less than 1.70 to 1.00, and steps up to 1.75 to 1.00 on September 30, 2022 and 2.00 to 1.00 as of December 31, 2022. As of March 31, 2021, DPL was in compliance with this financial covenant.

DPL’s secured revolving credit agreement also restricts 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, (i) 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, (ii) DPL’s senior long-term debt rating from two of the three major credit rating agencies is at least investment grade. As a result, as of March 31, 2021, DPL was prohibited from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).

AES Ohio's unsecured revolving credit agreementfacility and Bond Purchase and Covenants Agreement have two(financing document entered into in connection with the issuance of AES Ohio's First Mortgage Bonds, on July 31, 2020) has one financial covenants.covenant. The firstcovenant 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 ratio compares EBITDAAES Ohio’s Total Debt to Interest Expense and 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.


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32


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 (which is used for measuring the Total Debt to Total Capitalization ratio under eachshall not be greater than 0.67 to 1.00. As of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets2021, AES Ohio was inDP&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 September 30, 2017 is 0.46 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if DP&L's long-term indebtedness, as required by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.this financial covenant.


The cost of borrowing under DP&L's unsecured revolving credit agreement and Bond Purchase and Covenants Agreement adjust under certain credit rating scenarios.

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

The cost of borrowing under DPL's revolving credit agreement and term loan adjust under certain credit rating scenarios. DPL’s revolving credit agreement, term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES.

As of September 30, 2017, DP&LMarch 31, 2021, DPL and DPLAES Ohio were in compliance with all debt covenants, including the financial covenants described above.


AES Ohio does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.

Substantially all property, plant & equipment of DP&LAES Ohio is subject to the lien of the mortgage securing DP&L’sAES Ohio’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. On October 1, 2017, all the other DP&L generation assets transferred to AES Ohio Generation as part of Generation Separation were released from the lien of DP&L’s First and Refunding Mortgage. See Note 13 – Assets and Liabilities Held for Sale for additional information.


Note 87 – Income Taxes


The following table details the effective tax rates for the three and nine months ended September 30, 2017March 31, 2021 and 2016.2020.
Three months ended
March 31,
20212020
DPL(3.8)%(11.8)%
  Three months ended Nine months ended
  September 30, September 30,
  2017 2016 2017 2016
DPL 21.8% 45.7% 36.9% 38.6%


DPL’s effective combined state and federal income tax rate for all operations was (3.8)% for the three months ended March 31, 2021. This rate is different from the combined federal and state statutory rate of 22.5% primarily due to the flowthrough of the net tax benefit related to the reversal of excess deferred taxes of AES Ohio as a percentage of pre-tax book income.
Income
DPL's income tax expense for the ninethree months ended September 30, 2017 and 2016March 31, 2021 was calculated using the estimated annual effective income tax rates for 2017 and 20162021 of 36.0% and 38.6%, respectively.(3.8)%. Management estimates the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax resultsincome or loss.

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 year differ fromincome taxes associated with its own taxable income and records the forecasts applied to the most recent interim period, the estimated rates could be materially different from the actual effective tax rates. The effective tax rateprovision for the three months ended September 30, 2017 includes the impact of an adjustment relating to flow-through depreciation. The impact of this adjustment decreased the effective tax rate by 10.8% for the three months ended September 30, 2017. There is no impact on the effective tax rate for the nine months ended September 30, 2017.income taxes using a separate return method.


The decrease in the annual effective rate compared to the same period in 2016 is primarily due to the forecasted tax expense relating to flow-through depreciation and the projected manufacturer's production deduction.



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Note 98 – Benefit Plans


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


We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were $5.0$9.8 million and $7.5 million in employer contributions during each of the ninethree months ended September 30, 2017March 31, 2021 and 2016.2020, respectively.


The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The pension costs below have not been adjusted for amounts billed to the Service Company for former DP&LAES Ohio employees who are now employed by the Service Company butthat are still participants in the DP&LAES Ohio plan.


The net periodic benefit cost of the pension benefit plans for the three and nine months ended September 30, 2017March 31, 2021 and 20162020 was:
Three months ended
March 31,
$ in millions20212020
Service cost$1.1 $0.9 
Interest cost2.0 3.0 
Expected return on plan assets(3.7)(4.7)
Amortization of unrecognized:
Prior service cost0.2 0.3 
Actuarial loss2.3 1.5 
Net periodic benefit cost$1.9 $1.0 
22
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Service cost $1.5
 $1.4
 $4.3
 $4.2
Interest cost 3.5
 3.7
 10.6
 11.1
Expected return on plan assets (5.7) (5.7) (17.1) (17.1)
Plan curtailment (a)
 —
 —
 4.1
 —
Amortization of unrecognized:        
Prior service cost 0.2
 0.4
 0.8
 1.4
Actuarial loss 1.3
 1.1
 4.0
 3.2
Net periodic benefit cost $0.8
 $0.9
 $6.7
 $2.8


(a)
As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $4.1 million in the first quarter of 2017. See Note 14 – Fixed-asset Impairments for more information.

In addition, DP&LAES Ohio provides postretirement health care and life insurance benefits to certain retired employees, their spouses and eligible dependents. 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 $15.6$8.8 million at September 30, 2017March 31, 2021 and $15.8$9.0 million at December 31, 20162020 were not material to the financial statements in the periods covered by this report.


Benefit payments, which reflect future service, are estimated to be paid as follows:
$ in millions  
Estimated to be paid during Pension
2017 $6.3
2018 $25.5
2019 $26.0
2020 $26.4
2021 $26.7
2022 - 2026 $139.6

Note 109 – Contractual Obligations, Commercial Commitments and Contingencies


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

At September 30, 2017, DPL had $38.6 million With the completion of guarantees on behalf ofour plan to exit generation, AES Ohio Generation currently does not require such assurances to third parties, for future financial or performance assurance under such agreements. The guarantee arrangements entered into by


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DPL with these third parties cover select present and future obligations of AES Ohio Generation to such beneficiaries and are terminable by DPL upon written notice toexisting guarantees will expire in June 2021. During the beneficiaries within a certain time. The carrying amount of obligations for commercial transactions covered by these guarantees recorded in our Condensed Consolidated Balance Sheets was $1.2 million and $2.3 million at September 30, 2017 and Decemberthree months ended March 31, 2016, respectively.

To date, 2021, DPL has did not incurredincur any losses related to the guarantees of AES Ohio Generation’sthese obligations, and we believe it is remoteunlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees. At March 31, 2021, DPL had $1.9 million of such guarantees on behalf of AES Ohio Generation. There were no outstanding balances for commercial transactions covered by these guarantees at March 31, 2021 or December 31, 2020.


Equity Ownership Interest
DP&LAES Ohio has a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. AES Ohio, along with several non-affiliated energy companies party to an OVEC arrangement, receive and pay for OVEC capacity and energy and are responsible for OVEC debt obligations and other fixed costs in proportion to their power participation ratios under the arrangement, which, for AES Ohio, is the same as its equity ownership interest. At September 30, 2017, DP&LMarch 31, 2021, AES Ohio could be responsible for the repayment of 4.9%, or $71.3$62.0 million, of a $1,455.5$1,264.5 million OVEC debt obligationobligations if they came due, comprised of both fixed and variable rate securities with maturities from 20192022 to 2040. OVEC could also seek additional contributions from usAES Ohio to avoid a default in the event that other OVEC members defaulted on their respective OVEC obligations. As of September 30, 2017, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations
There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2016.


Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light ofconsidering the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2017,March 31, 2021, cannot be reasonably determined.


Environmental Matters
DPL’s and DP&L’sAES Ohio’s current and previously-owned 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 State Implementation Plans) 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 change;changes;
•
Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require substantial reductions in SO2, particulates, mercury, acid gases, NOx, and other air emissions. DPL 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, the Ohio EPA or other authorities that require or will require substantial reductions in SO2, particulates, mercury, acid gases, NOx and other air emissions;
•Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs;
23
•Rules and future rules issued by the USEPA, the Ohio EPA or other authorities 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 consists of fly ash and other coal combustion by-products.



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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 ofseveral 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 orand cash flows.


We have several pending environmental matters associated with our previously-owned and operated coal-fired generation units. Some of these matters could have a material adverse impactseffect on the operationour results of the power stations.operations, financial condition and cash flows.


Note 1110 – Business Segments


DPL currently manages theits business through two1 reportable operating segments,segment, the T&D segment and the GenerationUtility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure 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.segment. The segments areUtility segment is discussed further below:below.


Transmission and DistributionUtility Segment
The T&DUtility segment is comprised primarily of DP&L’sAES Ohio’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&LAES Ohio distributes electricity to more than 520,000approximately 532,000 retail customers located in a 6,000 square6,000-square mile area of West Central Ohio. DP&L’sAES Ohio’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&LAES Ohio applies the accounting standards for regulated operations to its electric transmission and distribution businesses recording 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&DUtility segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord,AES Ohio’s Hutchings Coal Station, which was closed in 2013 and East Bend generating facilities, which were either closed or sold in prior periods. As these assets did not transfertransferred to AES Ohio Generation on October 1, 2017 when DP&L’s generation separation occurred, 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 includeda third party in the T&D segment.fourth quarter of 2020.


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. Through September 30, 2017, AES Ohio Generation owned and operated peaking generating facilities, and DP&L owned multiple coal-fired and peaking electric generating facilities. As a result of Generation Separation, the DP&L-owned generating facilities were transferred to AES Ohio Generation on October 1, 2017. 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.

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’sDPL's long-term debt andas well as adjustments related to purchase accounting from the Merger. The accounting policies of the reportable segmentssegment are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies.Policies of our 10-K. Intersegment sales, costs of sales and expenses are eliminated in consolidation. Certain shared and corporate costs are allocated amongbetween "Other" and the Utility reporting segments.segment.




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36

The following tables present financial information for each of DPL’s Utility reportable business segments priorsegment:
$ in millionsUtilityOtherAdjustments and EliminationsDPL Consolidated
Three months ended March 31, 2021
Revenues from external customers$172.6 $2.6 $0 $175.2 
Intersegment revenues0.2 0.9 (1.1)0 
Total revenues$172.8 $3.5 $(1.1)$175.2 
Depreciation and amortization$18.7 $0.4 $0 $19.1 
Interest expense$6.0 $9.6 $0 $15.6 
Income / (loss) from continuing operations before income tax$21.5 $(7.6)$0 $13.9 
Capital expenditures$51.6 $0.3 $0 $51.9 
$ in millionsUtilityOtherAdjustments and EliminationsDPL Consolidated
Three months ended March 31, 2020
Revenues from external customers$168.7 $2.5 $0 $171.2 
Intersegment revenues0.3 0.8 (1.1)0 
Total revenues$169.0 $3.3 $(1.1)$171.2 
Depreciation and amortization$17.3 $0.4 $0 $17.7 
Interest expense$6.2 $12.7 $0 $18.9 
Income / (loss) from continuing operations before income tax$12.9 $(10.5)$0 $2.4 
Capital expenditures$39.3 $0.9 $0 $40.2 
Total AssetsMarch 31, 2021December 31, 2020
Utility$2,026.8 $2,014.7 
All Other (a)
26.7 21.3 
DPL Consolidated$2,053.5 $2,036.0 

(a)    "All Other" includes Eliminations for all periods presented.

Note 11 – Revenue

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the October 1, 2017 transfer to AES Ohio Generation:governmental authorities. For further discussion of our Retail, Wholesale, RTO ancillary, and Capacity revenues, see Note 14 — Revenue in Item 8.—Financial Statements and Supplementary Data of our Form 10-K.

DPL's revenue from contracts with customers was $172.1 million and $167.0 million for the three months ended March 31, 2021 and 2020, respectively.

25
$ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated
Three months ended September 30, 2017
Revenues from external customers $184.0
 $137.2
 $2.7
 $—
 $323.9
Intersegment revenues 0.2
 —
 0.9
 (1.1) —
Total revenues $184.2
 $137.2
 $3.6
 $(1.1) $323.9
           
Depreciation and amortization $19.6
 $4.7
 $3.0
 $—
 $27.3
Interest expense $7.7
 $—
 $19.5
 $—
 $27.2
Income / (loss) from continuing operations before income tax $20.0
 $29.9
 $(21.9) $—
 $28.0
           
Cash capital expenditures $20.6
 $7.9
 $0.7
 $—
 $29.2

$ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated
Three months ended September 30, 2016
Revenues from external customers $215.5
 $170.4
 $3.4
 $—
 $389.3
Intersegment revenues 0.3
 —
 2.0
 (2.3) —
Total revenues $215.8
 $170.4
 $5.4
 $(2.3) $389.3
           
Depreciation and amortization $17.8
 $7.7
 $5.4
 $—
 $30.9
Interest expense $6.5
 $0.1
 $20.5
 $(0.1) $27.0
Income / (loss) from continuing operations before income tax $36.4
 $14.2
 $(22.8) $—
 $27.8
           
Cash capital expenditures $19.6
 $10.6
 $0.5
 $—
 $30.7

$ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated
Nine months ended September 30, 2017
Revenues from external customers $541.7
 $396.4
 $7.8
 $—
 $945.9
Intersegment revenues 0.8
 —
 3.6
 (4.4) —
Total revenues $542.5
 $396.4
 $11.4
 $(4.4) $945.9
           
Depreciation and amortization $56.3
 $16.6
 $8.9
 $—
 $81.8
Fixed-asset Impairments (Note 14) $—
 $66.3
 $0.1
 $—
 $66.4
Interest expense $22.9
 $0.2
 $58.4
 $—
 $81.5
Income / (loss) from continuing operations before income tax $60.1
 $(43.7) $(62.8) $—
 $(46.4)
           
Cash capital expenditures $66.3
 $27.1
 $2.2
 $—
 $95.6
           
At September 30, 2017          
Total assets $1,655.3
 $333.0
 $694.4
 $(508.4) $2,174.3



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The following table presents our revenue from contracts with customers and other revenue by segment for the three months ended March 31, 2021 and 2020:
$ in millionsUtilityOtherAdjustments and EliminationsTotal
Three months ended March 31, 2021
Retail revenue
Retail revenue from contracts with customers
Residential revenue$98.3 $0 $0 $98.3 
Commercial revenue27.3 0 0 27.3 
Industrial revenue12.3 0 0 12.3 
Governmental revenue7.4 0 0 7.4 
Other (a)
3.7 0 0 3.7 
Total retail revenue from contracts with customers149.0 0 0 149.0 
Other retail revenue (b)
0 0 0 0 
Wholesale revenue
Wholesale revenue from contracts with customers5.0 0 (0.2)4.8 
RTO ancillary revenue14.8 0.1 0 14.9 
Capacity revenue0.9 0 0 0.9 
Miscellaneous revenue
Miscellaneous revenue from contracts with customers (c)
0 2.5 0 2.5 
Other miscellaneous revenue3.1 0.9 (0.9)3.1 
Total revenues$172.8 $3.5 $(1.1)$175.2 
Three months ended March 31, 2020
Retail revenue
Retail revenue from contracts with customers
Residential revenue$96.9 $0 $0 $96.9 
Commercial revenue28.9 0 0 28.9 
Industrial revenue11.8 0 0 11.8 
Governmental revenue9.3 0 0 9.3 
Other (a)
3.3 0 0 3.3 
Total retail revenue from contracts with customers150.2 0 0 150.2 
Other retail revenue (b)
3.3 0 0 3.3 
Wholesale revenue
Wholesale revenue from contracts with customers2.7 0 (0.2)2.5 
RTO ancillary revenue10.7 0 0 10.7 
Capacity revenue1.2 0 0 1.2 
Miscellaneous revenue
Miscellaneous revenue from contracts with customers (c)
0 2.4 0 2.4 
Other miscellaneous revenue0.9 0.9 (0.9)0.9 
Total revenues$169.0 $3.3 $(1.1)$171.2 

(a)    "Other" primarily includes Wright-Patterson Air Force Base revenues, billing service fees from CRES providers and other miscellaneous retail revenues from contracts with customers.
(b)    Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606.
(c)    Miscellaneous revenue from contracts with customers primarily includes revenues for various services provided by Miami Valley Lighting.

The balances of receivables from contracts with customers were $61.2 million and $70.1 million as of March 31, 2021 and December 31, 2020, respectively. Payment terms for all receivables from contracts with customers are typically within 30 days.

$ in millions T&D Generation Other Adjustments and Eliminations DPL Consolidated
Nine months ended September 30, 2016
Revenues from external customers $604.4
 $470.0
 $7.2
 $—
 $1,081.6
Intersegment revenues 1.0
 —
 4.2
 (5.2) —
Total revenues $605.4
 $470.0
 $11.4
 $(5.2) $1,081.6
           
Depreciation and amortization $55.1
 $44.6
 $0.6
 $—
 $100.3
Fixed-asset Impairments (Note 14) $—
 $857.1
 $(621.6) $—
 $235.5
Interest expense $17.5
 $0.3
 $61.7
 $(0.2) $79.3
Income / (loss) from continuing operations before income tax $97.9
 $(857.2) $564.8
 $—
 $(194.5)
           
Cash capital expenditures $61.8
 $46.9
 $1.1
 $—
 $109.8
           
At December 31, 2016          
Total assets $1,710.5
 $472.3
 $673.6
 $(437.2) $2,419.2

Note 12 – Discontinued Operations


Conesville - In May 2020, AEP, the operator of the formerly co-owned Conesville EGU, retired Conesville Unit 4 as planned. On January 1, 2016, June 5, 2020, DPL closed on and AES Ohio Generation, together with AEP, completed the saletransfer of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015, and DPL recorded a gain on this transaction of $49.2 milliontheir interests in the first quarterretired Unit 4, including the associated environmental liabilities, to an unaffiliated third-party purchaser. For the transaction, DPL will make quarterly cash expenditures, totaling $4.0 million, through July 2022,
26
of which $2.2 million has been paid through March 31, 2021. The gain includestransfer of Conesville Unit 4 was the impactlast step in DPL's plan to exit its AES Ohio Generation business operations.

DPL determined that the transfer of DPLER’s liability to DP&L that transferredConesville along with the sale on January 1, 2016 but was eliminatedtransfers of Stuart and Killen in consolidation2019 and the sales of the Peaker Assets in 2018 and Miami Fort and Zimmer in 2017 constitute the disposal of a group of components, which, as a whole, represent a strategic shift to exit its AES Ohio Generation business. As such, the disposal of December 31, 2015.

Operating activities relatedthis group of components qualifies to DPLER have been reclassified to "Discontinued operations"be presented as discontinued operations. Therefore, the results of operations of this group of components were reported as such in the Condensed Consolidated Statements of Operations for the nine months ended September 30, 2016.all periods presented.


The following table summarizes the revenues, cost of revenues, operating costs, other expenses and income tax of discontinued operations for the periods indicated:
Three months ended
March 31,
$ in millions20212020
Revenues$0.9 $13.6 
Operating costs and other expenses(1.7)(14.3)
Loss from discontinued operations before income tax(0.8)(0.7)
Income tax benefit from discontinued operations(0.2)(0.1)
Net loss from discontinued operations$(0.6)$(0.6)
$ in millions Nine months ended September 30, 2016
Operating expenses $(0.7)
Loss from discontinued operations before income taxes (0.7)
Gain from disposal of discontinued operations 49.2
Income tax expense 18.9
Income on discontinued operations $29.6


Cash flows related to discontinued operations are included in our Condensed Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7)$(0.2) million and $6.2 million for the ninethree months ended September 30, 2016.March 31, 2021 and 2020, respectively. Cash flows from investing activities for discontinued operations were $75.5 million for the nine months ended September 30, 2016. All cash generated from discontinued operations was paid to DPL through dividends for all periods presented.

Note 13 – Assets and Liabilities Held for Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the fourth quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of September 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The


38

following table summarizes the major classes of assets and liabilities classified as held for sale as of September 30, 2017:
$ in millions September 30, 2017
Assets  
Accounts receivable, net (a)
 $(11.2)
Inventories 22.7
Property, plant & equipment, net 44.8
Other prepayments and current assets 0.7
Total assets of the disposal group classified as held for sale in the balance sheet $57.0
   
Liabilities  
Accounts payable $0.7
Accrued taxes 2.6
Asset retirement obligations 4.4
Other liabilities (b)
 (0.7)
Total liabilities of the disposal group classified as held for sale in the balance sheet $7.0

(a)Represents credit balances netted in Accounts Receivable, due to the right of offset with partners
(b)Represents amounts due to (from) partners for pension benefits associated with partner-operated plants

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $11.0$(0.4) million and $1.4$5.1 million for the three months ended September 30, 2017March 31, 2021 and 2016, respectively, and $18.9 million and $(9.8) million for the nine months ended September 30, 2017 and 2016,2020, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.


Note 14 – Fixed-asset Impairments13 Risks and Uncertainties


On March 17, 2017, the Board of Directors of DP&L approved the retirementCOVID-19 Pandemic

The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility and negative pressure in financial markets. The global impact of the two DP&L operatedoutbreak has been rapidly evolving and co-owned electric generating stations;many countries, including the Stuart Station coal-firedU.S., have reacted by instituting quarantines, mandating business and diesel-fired generating unitsschool closures and social distancing measures as well as restricting travel. Responses to the COVID-19 pandemic by the State of Ohio and its residents and businesses, in particular, continue to evolve, including with respect to business and school closures and limitations and other social distancing measures and the Killen Station coal-fired generating uniteffectiveness and combustion turbine (collectively,timing of vaccine availability and distribution efforts. Social distancing measures designed to slow the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. We performed a long-lived asset impairment analysis and determined that the carrying amountsspread of the Facilities were not recoverable.virus, such as business closures and operations limitations, impact energy demand within our service territory. We are taking a variety of measures in response to the spread of COVID-19 to ensure our ability to transmit, distribute and sell electric energy, ensure the health and safety of our employees, contractors, customers and communities and provide essential services to the communities in which we operate. In addition to the impacts to demand within our service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, including those that relate to events outside of our control. The asset groupsmagnitude and duration of Stuart Stationthe COVID-19 pandemic is unknown at this time and Killen Station were determined tomay have fair valuesmaterial and adverse effects on our results of $3.3 millionoperations, financial condition and $7.9 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively.

Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Condensed Consolidated Statements of Operations.

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 amount 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, we recognized asset impairment expense of $230.8 million and $4.7 million for Killen and these DP&L peaking generating facilities, respectively.


periods.

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Table of Contents

























FINANCIAL STATEMENTS


The Dayton Power and Light CompanyAES Ohio




28
40
Table of Contents

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF OPERATIONS
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues $305.6
 $368.4
 $900.8
 $1,031.3
         
Cost of revenues:        
Net fuel cost 52.8
 71.0
 152.8
 189.5
Net purchased power cost 83.5
 110.0
 260.7
 328.0
Total cost of revenues 136.3
 181.0
 413.5
 517.5
         
Gross margin 169.3
 187.4
 487.3
 513.8
         
Operating expenses:        
Operation and maintenance 81.7
 85.5
 245.2
 248.0
Depreciation and amortization 22.7
 24.1
 68.2
 95.2
General taxes 19.6
 21.2
 66.8
 62.8
Gain on termination of contract —
 —
 —
 (27.7)
Fixed-asset impairment —
 —
 66.3
 857.1
Loss / (gain) on asset disposal (0.3) —
 15.9
 0.2
Other (4.4) —
 (4.4) —
Total operating expenses 119.3
 130.8
 458.0
 1,235.6
         
Operating income / (loss) 50.0
 56.6
 29.3
 (721.8)
         
Other expense, net        
Investment income 0.1
 0.1
 0.2
 0.3
Interest expense (7.7) (6.5) (23.1) (17.2)
Charge for early redemption of debt (1.0) (0.5) (1.1) (0.5)
Other expense (0.2) 0.1
 (1.5) (0.2)
Total other expense, net (8.8) (6.8) (25.5) (17.6)
         
Income / (loss) from operations before income tax 41.2
 49.8
 3.8
 (739.4)
         
Income tax expense / (benefit) 11.9
 19.7
 0.2
 (271.6)
         
Net income / (loss) 29.3
 30.1
 3.6
 (467.8)
         
Dividends on preferred stock —
 0.3
 —
 0.7
         
Income / (loss) attributable to common stock $29.3
 $29.8
 $3.6
 $(468.5)

AES Ohio
Condensed Statements of Operations
(Unaudited)
Three months ended
March 31,
$ in millions20212020
Revenues$172.8 $169.0 
Operating costs and expenses
Net fuel cost0.4 0.6 
Net purchased power cost71.2 62.4 
Operation and maintenance34.7 47.1 
Depreciation and amortization18.7 17.3 
Taxes other than income taxes20.3 20.8 
Other, net(0.1)(0.1)
Total operating costs and expenses145.2 148.1 
Operating income27.6 20.9 
Other income / (expense), net:
Interest expense(6.0)(6.2)
Other expense, net(0.1)(1.8)
Total other expense, net(6.1)(8.0)
Income before income tax21.5 12.9 
Income tax expense3.2 1.2 
Net income$18.3 $11.7 
See Notes to Condensed Financial Statements.
These interim statements are unaudited.
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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2017 2016 2017 2016
Net income / (loss) $29.3
 $30.1
 $3.6
 $(467.8)
Available-for-sale securities activity:        
Change in fair value of available-for-sale securities, net of income tax expense of $(0.1), $0.0, $(0.2) and $(0.1) for each respective period 0.1
 0.1
 0.4
 0.2
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $0.0 and $0.0 for each respective period —
 —
 (0.1) —
Total change in fair value of available-for-sale securities 0.1
 0.1
 0.3
 0.2
Derivative activity:        
Change in derivative fair value, net of income tax (expense) / benefit of $(0.8), $5.2, $(6.6) and $(12.2) for each respective period 1.4
 9.5
 12.1
 22.5
Reclassification to earnings, net of income tax benefit of $1.4, $3.0, $3.3 and $13.5 for each respective period (2.4) (5.6) (6.0) (24.8)
Total change in fair value of derivatives (1.0) 3.9
 6.1
 (2.3)
Pension and postretirement activity:        
Prior service costs for the period, net of income tax benefit of $0.0, $0.0, $0.6 and $0.0 for each respective period —
 —
 (1.1) —
Net loss for period, net of income tax benefit of $0.0, $0.0, $0.2 and $0.0 for each respective period —
 —
 (0.5) —
Reclassification to earnings, net of income tax expense of $(0.4), $(0.4), $(2.1) and $(1.6) for each respective period 0.7
 0.7
 3.8
 1.7
Total change in unfunded pension obligation 0.7
 0.7
 2.2
 1.7
         
Other comprehensive income / (loss) (0.2) 4.7
 8.6
 (0.4)
         
Net comprehensive income / (loss) $29.1
 $34.8
 $12.2
 $(468.2)

AES Ohio
Condensed Statements of Comprehensive Income
(Unaudited)
Three months ended
March 31,
$ in millions20212020
Net income$18.3 $11.7 
Derivative activity:
Change in derivative fair value, net of income tax expense of $0.0 and $0.0 for each respective period0 (0.3)
Reclassification to earnings, net of income tax benefit of $0.0 and $0.0 for each respective period0 (0.1)
Total derivative activity0 (0.4)
Pension and postretirement activity:
Reclassification to earnings, net of income tax benefit of $(0.3) and $(0.2) for each respective period1.0 0.8 
Total change in unfunded pension and postretirement obligations1.0 0.8 
Other comprehensive income1.0 0.4 
Net comprehensive income$19.3 $12.1 
See Notes to Condensed Financial Statements.
These interim statements are unaudited.
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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
AES OhioAES Ohio
Condensed Balance SheetsCondensed Balance Sheets
(Unaudited)(Unaudited)
$ in millions September 30, 2017 December 31, 2016$ in millionsMarch 31, 2021December 31, 2020
ASSETS    ASSETS  
Current assets:    Current assets:  
Cash and cash equivalents $15.3
 $1.6
Cash and cash equivalents$16.8 $11.7 
Restricted cash 2.0
 29.0
Restricted cash0.1 0.1 
Accounts receivable, net (Note 2) 107.9
 134.6
Inventories (Note 2) 26.9
 75.8
Accounts receivable, net of allowance for credit losses of $2.3 and $2.8, respectively (Note 2)Accounts receivable, net of allowance for credit losses of $2.3 and $2.8, respectively (Note 2)64.2 70.2 
InventoriesInventories9.1 8.8 
Taxes applicable to subsequent years 19.2
 79.2
Taxes applicable to subsequent years57.9 77.6 
Regulatory assets, current 4.5
 0.1
Regulatory assets, current35.1 27.5 
Other prepayments and current assets 21.8
 32.4
Assets held for sale - current (Note 13) 57.0
 —
Taxes receivableTaxes receivable30.7 32.5 
Prepayments and other current assetsPrepayments and other current assets9.6 6.4 
Total current assets 254.6
 352.7
Total current assets223.5 234.8 
    
Property, plant & equipment:    Property, plant & equipment:  
Property, plant & equipment 2,345.4
 2,398.6
Property, plant & equipment2,468.0 2,437.3 
Less: Accumulated depreciation and amortization (1,060.6) (1,047.9)Less: Accumulated depreciation and amortization(1,041.7)(1,032.1)
 1,284.8
 1,350.7
 1,426.3 1,405.2 
Construction work in process 52.3
 89.9
Construction work in process142.2 138.8 
Total net property, plant & equipment 1,337.1
 1,440.6
Total net property, plant & equipment1,568.5 1,544.0 
    
Other non-current assets:    Other non-current assets:  
Regulatory assets, non-current 209.4
 203.9
Regulatory assets, non-current191.9 193.6 
Intangible assets, net of amortization 19.9
 23.0
Intangible assets, net of amortization16.4 18.3 
Other deferred assets 12.3
 14.9
Other non-current assetsOther non-current assets26.5 24.0 
Total other non-current assets 241.6
 241.8
Total other non-current assets234.8 235.9 
Total assets $1,833.3
 $2,035.1
Total assets$2,026.8 $2,014.7 
    
LIABILITIES AND SHAREHOLDER'S EQUITY    LIABILITIES AND SHAREHOLDER'S EQUITY  
Current liabilities:    Current liabilities:  
Current portion of long-term debt (Note 7) $4.7
 $4.7
Short-term debt (Note 7) 15.0
 5.0
Short-term and current portion of long-term debt (Note 6)Short-term and current portion of long-term debt (Note 6)$80.2 $20.2 
Accounts payable 56.6
 110.5
Accounts payable65.5 85.5 
Accrued taxes 59.2
 75.7
Accrued taxes84.6 82.7 
Accrued interest 0.8
 2.1
Accrued interest5.9 2.6 
Security deposits 16.4
 15.2
Customer depositsCustomer deposits24.2 19.1 
Regulatory liabilities, current 20.0
 33.7
Regulatory liabilities, current21.6 18.0 
Other current liabilities 31.0
 48.3
Liabilities held for sale - current (Note 13) 6.0
 —
Accrued and other current liabilitiesAccrued and other current liabilities12.2 25.0 
Total current liabilities 209.7
 295.2
Total current liabilities294.2 253.1 
    
Non-current liabilities:    Non-current liabilities:  
Long-term debt (Note 7) 643.3
 744.7
Deferred taxes 155.1
 146.3
Long-term debt (Note 6)Long-term debt (Note 6)574.0 573.9 
Deferred income taxesDeferred income taxes177.7 172.1 
Taxes payable 4.8
 84.1
Taxes payable41.0 80.3 
Regulatory liabilities, non-current 134.5
 130.4
Regulatory liabilities, non-current214.4 218.3 
Pension, retiree and other benefits 100.7
 101.6
Unamortized investment tax credit 16.1
 17.7
Asset retirement obligations 131.0
 135.2
Other deferred credits 12.4
 17.6
Accrued pension and other post-retirement benefitsAccrued pension and other post-retirement benefits83.4 93.9 
Other non-current liabilitiesOther non-current liabilities6.1 6.4 
Total non-current liabilities 1,197.9
 1,377.6
Total non-current liabilities1,096.6 1,144.9 
    
Commitments and contingencies (Note 11) 
 
Commitments and contingencies (Note 9)Commitments and contingencies (Note 9)00
    
Common shareholder's equity:    Common shareholder's equity:  
Common stock, at par value of $0.01 per share 0.4
 0.4
Common stock, at par value of $0.01 per share0.4 0.4 
250,000,000 shares authorized, 41,172,173 shares issued and outstanding    
50,000,000 shares authorized, 41,172,173 shares issued and outstanding50,000,000 shares authorized, 41,172,173 shares issued and outstanding
Other paid-in capital 791.9
 810.7
Other paid-in capital714.4 714.4 
Accumulated other comprehensive loss (33.9) (42.5)Accumulated other comprehensive loss(41.1)(42.1)
Accumulated deficit (332.7) (406.3)Accumulated deficit(37.7)(56.0)
Total common shareholder's equity 425.7
 362.3
Total common shareholder's equity636.0 616.7 
Total liabilities and shareholder's equity $1,833.3
 $2,035.1
Total liabilities and shareholder's equity$2,026.8 $2,014.7 
See Notes to Condensed Financial Statements.
These interim statements are unaudited.
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THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
  Nine months ended September 30,
$ in millions 2017 2016
Cash flows from operating activities:    
Net income / (loss) $3.6
 $(467.8)
Adjustments to reconcile net income / (loss) to net cash from operating activities:    
Depreciation and amortization 68.2
 95.2
Charge for early redemption of debt 1.1
 0.5
Deferred income taxes 1.6
 (314.2)
Fixed-asset impairment 66.3
 857.1
Loss on asset disposal 15.9
 0.2
Changes in certain assets and liabilities:    
Accounts receivable 20.5
 (11.0)
Inventories 10.0
 29.4
Prepaid taxes —
 2.7
Taxes applicable to subsequent years 60.0
 59.9
Deferred regulatory costs, net (6.5) 19.5
Accounts payable (58.4) (13.5)
Accrued taxes payable (83.9) (43.2)
Accrued interest payable (1.5) (3.3)
Security deposits 1.1
 (0.6)
Pension, retiree and other benefits 3.8
 (2.2)
Other (3.1) 11.7
Net cash provided by operating activities 98.7
 220.4
Cash flows from investing activities:    
Capital expenditures (82.4) (98.3)
Purchase of renewable energy credits (0.1) (0.3)
Decrease in restricted cash 27.0
 5.5
Insurance proceeds 12.5
 5.6
Other investing activities, net 0.3
 0.9
Net cash used in investing activities (42.7) (86.6)
Cash flows from financing activities:    
Dividends and returns of capital paid to parent (19.0) —
Borrowings from revolving credit facilities 30.0
 —
Repayment of borrowings from revolving credit facilities (15.0) —
Capital contributions from parent 70.0
 —
Issuance of long-term debt, net of discount —
 442.8
Retirement of long-term debt (103.3) (445.3)
Payments of deferred financing costs —
 (8.0)
Issuance of short-term debt - related party 30.0
 5.0
Repayment of short-term debt - related party (35.0) (40.0)
Other financing activities, net —
 (0.8)
Net cash used in financing activities (42.3) (46.3)
Cash and cash equivalents:    
Net change 13.7
 87.5
Balance at beginning of period 1.6
 5.4
Cash and cash equivalents at end of period $15.3
 $92.9
Supplemental cash flow information:    
Interest paid, net of amounts capitalized $22.3
 $16.3
Income taxes paid, net $22.2
 $0.3
Non-cash financing and investing activities:    
Accruals for capital expenditures $7.7
 $10.1
Equity contribution to settle liability $—
 $7.5

AES Ohio
Condensed Statements of Cash Flows
(Unaudited)
Three months ended March 31,
$ in millions20212020
Cash flows from operating activities:
Net income$18.3 $11.7 
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization18.7 17.3 
Deferred income taxes3.2 3.0 
Changes in certain assets and liabilities:
Accounts receivable, net5.9 2.8 
Inventories(0.3)1.3 
Taxes applicable to subsequent years19.7 17.0 
Deferred regulatory costs, net(4.8)(5.0)
Accounts payable(4.3)(8.6)
Accrued taxes payable / receivable(38.8)(36.7)
Accrued interest3.2 4.1 
Accrued pension and other post-retirement benefits(10.5)(8.2)
Other1.0 1.3 
Net cash provided by operating activities11.3 0 
Cash flows from investing activities:
Capital expenditures(51.6)(39.3)
Cost of removal payments(4.5)(4.4)
Other investing activities, net(0.1)(0.7)
Net cash used in investing activities(56.2)(44.4)
Cash flows from financing activities:
Dividends and returns of capital paid to parent(10.0)0 
Borrowings from revolving credit facilities60.0 45.0 
Net cash provided by financing activities50.0 45.0 
Cash, cash equivalents, and restricted cash:
Net change5.1 0.6 
Balance at beginning of period11.8 21.3 
Cash, cash equivalents, and restricted cash at end of period$16.9 $21.9 
Supplemental cash flow information:
Interest paid, net of amounts capitalized$2.7 $0.7 
Non-cash financing and investing activities:
Accruals for capital expenditures$16.0 $4.8 
See Notes to Condensed Financial Statements.
These interim statements are unaudited.
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AES Ohio
The Dayton Power and Light CompanyCondensed Statements of Shareholder's Equity
(Unaudited)

Common Stock (a)
$ in millionsOutstanding SharesAmountOther Paid-in CapitalAccumulated Other Comprehensive LossAccumulated DeficitTotal
Balance, January 1, 202141,172,173 $0.4 $714.4 $(42.1)$(56.0)$616.7 
Net comprehensive income1.0 18.3 19.3 
Balance, March 31, 202141,172,173 $0.4 $714.4 $(41.1)$(37.7)$636.0 

(a)    $0.01 par value, 50,000,000 shares authorized.

Common Stock (a)
$ in millionsOutstanding SharesAmountOther Paid-in CapitalAccumulated Other Comprehensive LossAccumulated DeficitTotal
Balance, January 1, 202041,172,173 $0.4 $617.0 $(36.9)$(107.1)$473.4 
Net comprehensive income0.4 11.7 12.1 
Balance, March 31, 202041,172,173 $0.4 $617.0 $(36.5)$(95.4)$485.5 

(a)$0.01 par value, 50,000,000 shares authorized.

See Notes to Condensed Financial Statements (Unaudited)Statements.


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AES Ohio
Notes to Unaudited Condensed Financial Statements

Note 1 – Overview and Summary of Significant Accounting Policies


Description of Business
DP&L, which does business as AES Ohio, 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, retail transmission and distribution services are still regulated. DP&LAES Ohio has the exclusive right to provide such transmission and distribution services to approximately 520,000532,000 customers located in West Central Ohio. Additionally, DP&L procuresAES Ohio provides retail SSO electric service on behalf ofto residential, commercial, industrial and governmental customers in a 6,000 square6,000-square mile area of West Central Ohio. As of September 30, 2017, DP&L owned undivided interests in multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities. As of October 1, 2017, the DP&L-owned generating facilities were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL, through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. With the October 1, 2017 transfer of DP&L's generation assets to a separate DPL subsidiary, DP&L has discontinued its generation business operations. Also, Stuart Station Unit 1 was retired on October 1, 2017. DP&L sources 100%all of the generation for its SSO customers through a competitive bid process. Principal industries located in DP&L’sAES Ohio’s service territory include automotive, food processing, paper, plastic, health care, data management, manufacturing and defense. DP&L's distributionAES Ohio's sales reflect the general economic conditions, seasonal weather patterns of the proliferation of energy efficiency and distributed renewable resourcesarea and the market price of electricity. From January 1, 2016 through September 30, 2017, DP&L sold allAES Ohio owned interests in the retired Hutchings Coal Station until its transfer in 2020, and currently owns numerous transmission facilities. AES Ohio sells its proportional share of its energy and capacity from its investment in OVEC into the wholesale market. DP&LAES Ohio has 1 reportable segment, the Utility segment. In addition to AES Ohio's electric transmission and distribution businesses, the Utility segment includes revenues and costs associated with AES Ohio's investment in OVEC and the historical results of AES Ohio’s Hutchings Coal Station. AES Ohio is a subsidiary of DPLDPL. The terms “we,” “us,” “our” and “ours” are used to refer to AES Ohio.


Through September 30, 2017, DP&L had two reportable segments: the Transmission and Distribution (T&D) segment and the Generation segment. See Note 12 – Business Segments for more information relating to these reportable segments.

DP&L’sAES Ohio’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&LAES Ohio 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.costs or overcollections of riders.

DP&L employed 1,065 people as of September 30, 2017. As part of Generation Separation on October 1, 2017, DP&L generation employees became employees of AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL. Approximately 61% of DP&L and AES Ohio Generation employees are under a collective bargaining agreement that was set to expire on October 31, 2017. The Company and the union representing these employees have agreed to extend the current agreement through January 31, 2018, while continuing to negotiate a new agreement. We are unable to determine what impact a new agreement may have on our operations.


Financial Statement Presentation
DP&LAES Ohio does not have any subsidiaries. As of September 30, 2017, DP&L had undivided ownership interests in five coal-fired generating facilities, various peaking generating facilities and numerous transmission facilities, all of which are included in

We have evaluated subsequent events through the financial statements at the lower of depreciated historical cost or fair value, if impaired. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statements of Operations.date this report is issued.


Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation.

In the current period, we have reclassified the presentation of the December 2016 dividend payment which was originally recorded as a charge to Accumulated deficit and is now presented as a charge to Other paid-in capital. This reclassification was to prospectively correct an immaterial error.


These financial statements have been prepared in accordance with GAAP, as contained in the FASB ASC, for interim financial statements and Article 10 of Regulation S-X issued by the instructions of Form 10-Q and Regulation S-X.SEC. Accordingly, certainthey do not include all the information and footnote disclosures normally included in thefootnotes required by GAAP for annual financial statements prepared in accordance with GAAP have been omitted from this interim report.fiscal reporting periods. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2016.2020.


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In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of September 30, 2017;March 31, 2021; our results of operations for the three and nine months ended September 30, 2017March 31, 2021 and 2016 and2020, our cash flows for the ninethree months ended September 30, 2017March 31, 2021 and 2016.2020 and the changes in our equity for the three months ended March 31, 2021 and 2020. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including, but not limited to, seasonal weather variations, the timing of outages of EGUs, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2017March 31, 2021 may not be indicative of our results that will be realized for the full year ending December 31, 2017.2021.


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: recognition of revenue including unbilled revenues, 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 receivablescredit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.


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Cash, Cash Equivalents and Restricted Cash
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Condensed Balance Sheets that reconcile to the total of such amounts as shown on the Condensed Statements of Cash Flows:
$ in millionsMarch 31, 2021December 31, 2020
Cash and cash equivalents$16.8 $11.7 
Restricted cash0.1 0.1 
Cash, Cash Equivalents, and Restricted Cash, End of Period$16.9 $11.8 

Inventories
Inventories consist of materials and supplies at March 31, 2021 and December 31, 2020.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&LAES Ohio collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended September 30, 2017March 31, 2021 and 20162020 were $13.0$12.9 million and $14.4$12.4 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2017 and 2016 were $36.9 million and $38.9 million, respectively.


New Accounting Pronouncements
Issued But Not Yet Effective – The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements:
statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our financial statements.
Accounting StandardASU Number and NameDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Adopted
2016-09, Compensation - Stock Compensation2020-04, Reference Rate Form (Topic 718)848): Improvements to Employee Share-Based Payment AccountingFacilitation of the Effects of Reference Rate Reform on Financial ReportingThe standard simplifies the following aspects of accountingprovides optional expedients and exceptions for share-based payments 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 equityapplying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR 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 recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis.		January 1, 2017.The primary effect of adoption was 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. The adoption of this standard did not have a material impact on the financial statements.


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Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
New Accounting Standards Issued But Not Yet Effective
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging ActivitiesThe standard updates the hedge accounting model in ASC 815 to expand the ability to hedge risk, reduce complexity and ease certain documentation and assessment requirements. It also eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrumentanother reference rate expected to be presented in the same income statement line as the hedged item.
Transition method: modified retrospective approach and prospectivediscontinued by reference rate reform. This standard is effective for presentation and disclosures.a limited period of time (March 12, 2020 - December 21, 2022).		January 1, 2019.
Early adoption is permitted.Effective for all entities March 12, 2020 - December 31, 2022		We are currently evaluating the impact of adopting the standard on our financial statements and if we would early adopt it.
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt SecuritiesThis standard shortens the period of amortization of the premium on certain callable debt securities to the earliest call date.
Transition method: modified retrospective.		January 1, 2019.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on ourcondensed financial statements.
2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit CostThis standard changes the presentation of non-service cost expense associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization.
Transition method: Retrospective for presentation of non-service cost expense. Prospective for the change in capitalization.
January 1, 2018.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on our financial statements.
2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of businesses is under scope of ASC 810.
Transition method: full or modified retrospective we are in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of the balance sheet date, the contracts that may require any type of assessment under the new standard are limited.		January 1, 2018.We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the financial statements. We will adopt the standard on January 1, 2018 and plan to use the modified retrospective approach.
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.
Transition method: prospective.		January 1, 2018.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on our financial statements.
2016-18, Statement of Cash Flows (Topic 230): 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.
2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than InventoryThis standard requires that an entity recognize 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.



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Accounting StandardDescriptionDate of AdoptionEffect on the financial statements upon adoption
2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial InstrumentsThis 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.
2016-02, Leases (Topic 842)This standard requires lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions.
Transition method: modified retrospective at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).

We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.		January 1, 2019.
Early adoption is permitted.		We are currently evaluating the impact of adopting the standard on our financial statements. We intend to adopt the standard as of January 1, 2019.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-05, 2017-13 Revenue from Contracts with Customers (Topic 606)See discussion of the ASUs below.January 1, 2018.We will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the financial statements.

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP.

In 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. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

Given the complexity and diversity of our non-regulated arrangements, we are assessing the standard on a contract-by-contract basis and are in the process of completing the contract assessments by applying interpretations reached during 2017 on key issues. These issues include the application of the practical expedient for measuring progress towards 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 allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. We will continue our work to complete the assessment of the full population of contracts and determine the overall impact to the consolidated financial statements.

The standard requires retrospective application and allows either a full retrospective adoption in which all periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. Although we had previously been working toward adopting the standard using the full retrospective method, given the limited situations where revenue recognized under ASC 606 differs from that recognized under ASC 605, we now expect to use the modified


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retrospective approach. However, we will continue to assess this conclusion which is dependent on the final impact to the financial statements.

We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues which is expected in 2017.

Note 2 – Supplemental Financial Information


Accounts receivable and Inventories are as follows at September 30, 2017March 31, 2021 and December 31, 2016:2020:
March 31,December 31,
$ in millions20212020
Accounts receivable, net:
Customer receivables$44.6 $47.6 
Unbilled revenue15.5 21.6 
Amounts due from affiliates2.1 1.9 
Due from PJM transmission enhancement settlement1.7 1.7 
Other2.6 0.2 
Allowance for credit losses(2.3)(2.8)
Total accounts receivable, net$64.2 $70.2 

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the three months ended March 31, 2021 and 2020:
$ in millionsBeginning Allowance BalanceCurrent Period ProvisionWrite-offs Charged Against AllowancesRecoveries CollectedEnding Allowance Balance
2021$2.8 $0 $(0.7)$0.2 $2.3 
2020$0.4 $0.4 $(0.4)$0.3 $0.7 

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, including the economic impacts of the COVID-19 pandemic on our receivable balance as of March 31, 2021. Amounts are written off when reasonable collections efforts have been exhausted. During 2021, the current period provision and allowance for credit losses
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  September 30, December 31,
$ in millions 2017 2016
Accounts receivable, net:    
Unbilled revenue $14.4
 $43.0
Customer receivables 68.7
 71.2
Amounts due from affiliates 2.3
 2.9
Amounts due from partners in jointly-owned plants 17.8
 12.7
Other 5.8
 6.0
Provision for uncollectible accounts (1.1) (1.2)
Total accounts receivable, net $107.9
 $134.6
     
Inventories, at average cost:    
Fuel and limestone $16.8
 $38.8
Plant materials and supplies 9.1
 35.3
Other 1.0
 1.7
Total inventories, at average cost $26.9
 $75.8
have decreased due to lower past due customer receivable balances. See Note 12 – Risks and Uncertainties for additional discussion of the COVID-19 pandemic.


Accumulated Other Comprehensive Income / (Loss)Loss
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss)Loss by component during the three and nine months ended September 30, 2017March 31, 2021 and 20162020 are as follows:
Details about Accumulated Other Comprehensive Loss componentsAffected line item in the Condensed Statements of OperationsThree months ended
March 31,
$ in millions20212020
Gains and losses on cash flow hedges (Note 5):
Interest expense$0 $(0.1)
Income tax benefit0 0 
Net of income taxes0 (0.1)
Amortization of defined benefit pension items (Note 8):
Other expense1.3 1.0 
Income tax benefit(0.3)(0.2)
Net of income taxes1.0 0.8 
Total reclassifications for the period, net of income taxes$1.0 $0.7 
Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Consolidated Statements of Operations Three months ended Nine months ended
    September 30, September 30,
$ in millions   2017 2016 2017 2016
Gains and losses on Available-for-sale securities activity (Note 5):
  Other income $—
 $—
 $(0.1) $—
           
Gains and losses on cash flow hedges (Note 6):        
  Interest expense (0.3) (0.3) (0.8) (0.9)
  Revenue (4.2) (9.3) (12.5) (46.5)
  Purchased power 0.7
 1.0
 4.0
 9.1
  Total before income taxes (3.8) (8.6) (9.3) (38.3)
  Tax expense 1.4
 3.0
 3.3
 13.5
  Net of income taxes (2.4) (5.6) (6.0) (24.8)
           
Amortization of defined benefit pension items (Note 9):        
  Operation and maintenance 1.1
 1.1
 5.9
 3.3
  Tax benefit (0.4) (0.4) (2.1) (1.6)
  Net of income taxes 0.7
 0.7
 3.8
 1.7
           
Total reclassifications for the period, net of income taxes $(1.7) $(4.9) $(2.3) $(23.1)



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The changes in the components of Accumulated Other Comprehensive Income / (Loss)other comprehensive loss during the ninethree months ended September 30, 2017March 31, 2021 are as follows:
$ in millionsChange in Accumulated other comprehensive loss
Balance at January 1, 2021$(42.1)
Amounts reclassified from AOCL to earnings1.0
Net current period other comprehensive income1.0
Balance at March 31, 2021$(41.1)

$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance at January 1, 2017 $0.7
 $(2.7) $(40.5) $(42.5)
         
Other comprehensive income / (loss) before reclassifications 0.4
 12.1
 (1.6) 10.9
Amounts reclassified from accumulated other comprehensive income / (loss) (0.1) (6.0) 3.8
 (2.3)
Net current period other comprehensive income 0.3
 6.1
 2.2
 8.6
         
Balance at September 30, 2017 $1.0
 $3.4
 $(38.3) $(33.9)


Note 3 – Regulatory Matters


In January 2017, DP&L filedESP and SEET Proceedings
On October 23, 2020, AES Ohio entered into a Stipulation and Recommendation (settlement) with the staff of the PUCO and various customers, and organizations representing customers of AES Ohio and certain other parties with respect to, among other matters, AES Ohio's applications pending at the PUCO for (i) approval of AES Ohio's plan to modernize its distribution grid (the Smart Grid Plan), (ii) findings that AES Ohio passed the SEET for 2018 and 2019, and (iii) findings that AES Ohio's current ESP 1 satisfies the SEET and the more favorable in the aggregate (MFA) regulatory test. The settlement in its ESP 3 case and filed an amended stipulation on March 13, 2017, which wasis subject to, and conditioned upon, approval by the PUCO. A final decisionhearing was issuedheld in January 2021 for consideration of this settlement; a commission order is pending.

Decoupling
On January 23, 2020 AES Ohio filed with the PUCO requesting approval to defer its decoupling costs consistent with the methodology approved in its Distribution Rate Case. If approved, deferral would be effective December 18, 2019 and going forward would reduce impacts of weather, energy efficiency programs and economic changes in customer demand. An evidentiary hearing was held on this matter on May 4, 2021.

Distribution Rate Case
On November 30, 2020, AES Ohio filed a new Distribution Rate Case with the PUCO. This rate case proposes a revenue increase of $120.8 million per year and incorporates the DIR investments that were planned and approved in the last rate case but not yet included in distribution rates, other distribution investments since September 2015 and investments necessitated by the PUCOtornados that occurred on October 20, 2017, modifyingMemorial Day in 2019. The rate case also includes a proposal for increased tree-trimming expenses and adoptingcertain customer demand-side management programs and
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recovery of prior-approved regulatory assets for tree trimming, uncollectible expenses and rate case expense. This case is pending a commission order.

FERC Proceedings
On November 15, 2018 the amended stipulationFERC issued a Notice of Proposed Rulemaking (NOPR) to address amortization of excess accumulated deferred income taxes resulting from the TCJA and recommendation. The ESP establishes DP&L's framework for providing retail servicetheir impact on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory parties agreedtransmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;
The establishment of a three-year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 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. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;
The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments,determine the amount of which is to be established in a separate DP&L distribution rate case
A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs;
Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order to be effective November 1, 2017;
A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L; and
Restrictions on DPL making dividend or tax sharing payments; and
Various other riders and competitive retail market enhancements.

In connection with any sale or closure of our generation plants as contemplatedexcess deferred income taxes caused by the ESPTCJA. On March 3, settlement or otherwise, DPL and DP&L would expect2020, AES Ohio filed an application before the FERC to incur certain cash and non-cash charges, some or all ofchange its transmission rate from a stated rate to a formula rate, which could be material to the business and financial condition of DPL and DP&L.

DP&L’s ESP 2 had been approvedwas accepted by the PUCO forFERC and made effective as of May 3, 2020, subject to further proceeding and potential refunds. An uncontested settlement was filed December 10, 2020, which would increase the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion statedrates that the PUCO’s approval of the ESP was reversed. In view of that reversal, DP&L filed a motion to withdraw its ESP 2 and implement rates consistent with thosewere in effect prior to 2014.the filing but are a reduction from the rate that became effective subject to refund on May 3, 2020. Among other things, the settlement establishes new depreciation rates for our transmission assets and an authorized return on equity (ROE) of 9.85%, which would rise to 9.99% if the FERC were to approve in a separate ongoing proceeding a return on equity “adder” to recognize our continued membership in PJM. The PUCO approved DP&L’s withdrawal of ESP 29.85% ROE (base) and implementation plans. Those rates were in effect until rates approved as a result of DP&L’s pending ESP 39.99% ROE (base + incentive) levels are effective, November 1, 2017. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court.


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Those appeals are pending, and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending. That stay was denied by the Ohio Supreme Court in September 2017.

DP&L is subject to a SEET thresholdfour-year moratorium on other proposed ROE changes. Proposals to raise or lower the ROE could be filed with an effective date after the moratorium expires on April 14, 2025. The required flowback of excess deferred taxes under the NOPR was also addressed and is requiredresolved as part of this formula transmission rate settlement. On April 15, 2021, the FERC approved the transmission rate settlement.

Note 4 – Fair Value

The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair values of our assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions 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 ESP 3 maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded fromsell assets or transfer liabilities, the SEET calculation. A stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending. In future years, the SEET coulduse of different market assumptions and/or estimation methodologies may have a material effect on results of operations, financial condition and cash flows.

Note 4 – Property, Plant and Equipment

Coal-fired facilities
As of September 30, 2017, DP&L and certain other Ohio utilities had 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. DP&L’s share of the operations of such facilities is included within the corresponding line in the Condensed 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 Condensed Balance Sheets, except for amounts related to Miami Fort and Zimmer, which are classified as Held for Sale, as described below. Each co-owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.

DP&L’s undivided ownership interest in such facilities at September 30, 2017, was as follows:
  
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)
Jointly-owned production units          
Conesville - Unit 4 16.5 129
 $0.5
 $0.5
 $2.3
Killen - Unit 2 67.0 402
 8.5
 4.1
 —
Miami Fort - Units 7 and 8 (a) 36.0 368
 31.3
 3.3
 5.1
Stuart - Units 2 through 4 35.0 606
 0.7
 0.7
 —
Zimmer - Unit 1 (a) 28.1 371
 21.3
 15.3
 5.2
Transmission (at varying percentages)     98.6
 66.9
 —
Total   1,876
 $160.9
 $90.8
 $12.6

(a)
DP&L has entered into an agreement to sell its interest in these units. See Note 13 – Assets and Liabilities Held for Sale for additional information.

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

On January 10, 2017, a high-pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. As a result, $6.4 million of net book value was written off, resulting in a $3.2 million loss on disposal, net of accrued insurance recoveries, which was recorded during the first quarter of 2017. This loss was reversed during the second quarter of 2017 due to additional accrued insurance recoveries. This unit was retired on October 1, 2017. Accordingly, the 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the DP&L operated and co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement.


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On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the fourth quarter of 2017.

On October 1, 2017, Generation Separation was completed and the coal-fired electric generating facilities described above were transferred to AES Ohio Generation. The portion of the co-owned transmission facilities owned by DP&L remains owned by DP&L.

AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at theirestimated 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 assetamounts. For further information on our valuation techniques and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirementpolicies, see Note 5—Fair Value in Item 8. — Financial Statements and Supplementary Data of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities.Form 10-K.

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 January 1, 2017$135.2
Additions0.1
Revisions to cash flow and timing estimates(4.8)
Accretion expense4.0
Settlements(0.1)
Reclassified to Liabilities held for sale(3.4)
Balance at September 30, 2017$131.0

See Note 5 – Fair Value for further discussion on changes to our AROs.

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



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The following table presents the fair value, carrying value and cost of our non-derivative instruments at September 30, 2017March 31, 2021 and December 31, 2016. Information2020. Further information about the fair value of our derivative instruments can be found in Note 65 – Derivative Instruments and Hedging Activities.
March 31, 2021December 31, 2020
$ in millionsCostFair ValueCostFair Value
Assets
Money market funds$0.2 $0.2 $0.3 $0.3 
Equity securities2.0 4.7 2.1 4.5 
Debt securities3.8 3.8 4.0 4.1 
Total assets$6.0 $8.7 $6.4 $8.9 
Carrying ValueFair ValueCarrying ValueFair Value
Liabilities
Long-term debt$574.2 $599.7 $574.1 $656.0 
  September 30, 2017 December 31, 2016
$ in millions Cost Fair Value Cost Fair Value
Assets        
Money market funds $0.4
 $0.4
 $0.4
 $0.4
Equity securities 2.6
 4.1
 2.4
 3.4
Debt securities 4.2
 4.3
 4.4
 4.4
Hedge funds 0.1
 0.1
 —
 0.1
Real estate —
 —
 0.3
 0.3
Tangible assets 0.1
 0.1
 0.1
 0.1
Total assets $7.4
 $9.0
 $7.6
 $8.7
         
  Carrying Value Fair Value Carrying Value Fair Value
Liabilities        
Long-term debt (a) $647.7
 $659.5
 $749.0
 $763.5

(a)Amounts exclude immaterial capital lease obligations


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

Fair Value Hierarchy
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
Level 1 (quoted prices in active markets for identical assets or liabilities);
Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or
Level 3 (unobservable inputs) 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, Level 2 or Level 3 of the fair value hierarchy during the ninethree months ended September 30, 2017March 31, 2021 or 2016.2020.


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

DP&L had $1.5 million ($1.0 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at September 30, 2017 and $1.1 million ($0.7 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2016.

During the nine months ended September 30, 2017, $0.8 million ($0.6 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial

equity

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amount ofinvestments. We recorded net unrealized gains / (losses) of $0.2 million and $(1.1) million during the during the three months ended March 31, 2021 and 2020, respectively. These amounts are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distributionincluded in "Other expense, net" in our Condensed Statements of benefits.Operations.


Long-term 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 long-term debt is presented at cost,carrying value, net of unamortized premium or discount and unamortized deferred financing costs in the financial statements. The long-term debt amounts include the current portion payable in the next twelve months and have maturities that range from 20202040 to 2061.


The fair value of assets and liabilities at September 30, 2017March 31, 2021 and December 31, 20162020 and the respective category within the fair value hierarchy for DP&L was determinedAES Ohio is as follows:
$ in millionsFair value at March 31, 2021 (a)Fair value at December 31, 2020 (a)
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Master Trust assets
Money market funds$0.2 $0 $0 $0.2 $0.3 $0 $0 $0.3 
Equity securities0 4.7 0 4.7 0 4.5 0 4.5 
Debt securities0 3.8 0 3.8 0 4.1 0 4.1 
Total assets$0.2 $8.5 $0 $8.7 $0.3 $8.6 $0 $8.9 
Liabilities
Long-term debt$0 $582.4 $17.3 $599.7 $0 $638.6 $17.4 $656.0 
Total liabilities$0 $582.4 $17.3 $599.7 $0 $638.6 $17.4 $656.0 
Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair value at September 30, 2017 (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 4.1
 —
 4.1
 —
Debt securities 4.3
 —
 4.3
 —
Hedge funds 0.1
 —
 0.1
 —
Tangible assets 0.1
 —
 0.1
 —
Total Master Trust assets 9.0
 0.4
 8.6
 —
Derivative assets        
Natural gas futures 0.9
 0.9
 —
 —
Interest rate hedges —
 —
 —
 —
Forward power contracts 10.8
 —
 10.8
 —
Total derivative assets 11.7
 0.9
 10.8
 —
         
Total assets $20.7
 $1.3
 $19.4
 $—
         
Liabilities        
Derivative liabilities        
FTRs $0.5
 $—
 $—
 $0.5
Interest rate hedges —
 —
 —
 —
Natural gas futures 0.8
 0.8
 —
 —
Forward power contracts 8.1
 —

8.1
 —
Total derivative liabilities 9.4
 0.8
 8.1
 0.5
Long-term debt (b) 659.5
 —
 641.6
 17.9
         
Total liabilities $668.9
 $0.8
 $649.7
 $18.4


(a)(a)    Includes credit valuation adjustment
(b)Amounts exclude immaterial capital lease obligations



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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 hedges 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        
Derivative liabilities        
Interest rate hedges $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 (b) 763.5
 —
 745.5
 18.0
         
Total liabilities $792.7
 $—
 $772.2
 $20.5

(a)Includes credit valuation adjustment
(b)Amounts exclude immaterial capital lease obligations

Our financial instruments are valued using the market approach in the following categories:
Level 1 inputs are used for derivative contracts such as natural gas 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 in the Master Trust, which are valued using the end of day NAV per unit.
Level 3 inputs such as FTRs are considered a Level 3 input because the monthly auctions are considered inactive. Other Level 3 inputs include the credit valuation adjustment on some of the forward power contracts and forward power contracts in less active markets. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.
Approximately 86%
All of the inputs to the fair value of our derivative instruments are from quoted market prices.


Our long-term 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. As the Wright-Patterson Air Force Base note is not publicly traded, fair value is assumed to equal carrying value. Thesethe fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures are not presented since our long-term debt is not recorded at fair value.




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Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs, which is estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. As a result of changes in our estimates of costs to be incurred for our AROs, we decreased our AROs by $4.8 million in the first nine months of 2017. AROs for ash ponds, asbestos, ash landfills, river structures and underground storage tanks decreased by a net amount of $0.8 million and increased by a net amount of $3.0 million during the nine months ended September 30, 2017 and 2016, respectively. In addition, there was a $3.4 million decrease in the ARO liability during the nine months ended September 30, 2017 related to AROs at Miami Fort and Zimmer being reclassified to Liabilities held for sale - current.

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018, and the co-owners of the Facilities agreed with DP&L to proceed with this plan of retirement. As a result, we performed a long-lived asset impairment analysis during the first quarter of 2017 and determined that the carrying amounts of the Facilities were not recoverable. See Note 14 – Fixed-asset Impairments.

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 the Stuart, Killen and Zimmer EGUs. As a result, we performed a long-lived asset impairment analysis during the second quarter of 2016 and determined that the carrying amount of these assets were not recoverable. See Note 14 – Fixed-asset Impairments.

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 Long-lived assets measured at fair value on a non-recurring basis during the periods and their level within the fair value hierarchy:
  Carrying Fair Value Gross
  
Amount (b)
 Level 1 Level 2 Level 3 Loss
$ in millions Nine months ended September 30, 2017
Assets          
Long-lived assets (a)
          
Stuart $42.3
 $—
 $—
 $3.3
 $39.0
Killen $35.2
 $—
 $—
 $7.9
 $27.3
          $66.3
           
  Nine months ended September 30, 2016
Assets          
Long-lived assets (a)
          
Stuart $456.4
 $—
 $—
 $164.4
 $292.0
Killen $330.5
 $—
 $—
 $84.3
 $246.2
Zimmer $429.9
 $—
 $—
 $111.0
 $318.9
          $857.1

(a)See Note 14 – Fixed-asset Impairments for further information
(b)Carrying amount at date of valuation



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The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the nine months ended September 30, 2017:
$ in millions Fair value Valuation technique Unobservable input Weighted average
Long-lived assets held and used:
Stuart $3.3
 Discounted cash flow Pre-tax operating margin
(through remaining life)		 10.0%
      Weighted-average cost of capital 7.0%
         
Killen $7.9
 Discounted cash flow Pre-tax operating margin
(through remaining life)		 22.0%
      Weighted-average cost of capital 7.0%

The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the nine months ended September 30, 2016:
$ in millions Fair value Valuation technique Unobservable input Weighted average
Long-lived assets held and used:
Stuart $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 $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 $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 65 – 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 ofFor further information on our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 forhedge accounting purposes.policies, See Note 1 – Overview and Summary of Significant Accounting Policies – Financial Derivatives and Note 6 - Derivative Instruments and Hedging Activities of Item 8 – Financial Statements and Supplementary Data in our Form 10-K.



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At September 30, 2017, DP&L's derivative instruments were as follows:
Commodity 
Accounting Treatment (a)
 Unit Purchases
(in thousands)		 Sales
(in thousands)		 Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 3.4
 —
 3.4
Natural gas futures Not designated Dths 6,625.0
 (390.0) 6,235.0
Forward power contracts Designated MWh 649.0
 (2,478.9) (1,829.9)
Forward power contracts Not designated MWh 1,082.8
 (1,060.0) 22.8
Interest rate swaps Designated USD $200,000.0
 $—
 $200,000.0

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

At December 31, 2016, DP&L's derivative instruments were as follows:
Commodity 
Accounting Treatment (a)
 Unit Purchases
(in thousands)		 Sales
(in thousands)		 Net Purchases/ (Sales)
(in thousands)
FTRs Not designated MWh 2.3
 —
 2.3
Natural gas futures 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

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.


Cash Flow Hedges
As part of our risk management processes, we identifyIn August 2020, 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 have two interest rate swaps to hedge the variable interest on our $200.0the $140.0 million variable interest rate tax-exempt First Mortgage Bonds.Bonds expired, as the associated debt reached maturity. The interest rate swaps havehad a combined notional amount of $200.0$140.0 million and will settlesettled monthly based on a one monthone-month LIBOR. We use the income approach to valueThe AOCL associated with the swaps which consistswas amortized out of forecasting future cash flows based on contractual notional amounts and applicable and available market data asAOCL into interest expense over the life 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.underlying debt.




38
58

The following tables provide information concerning gains or losses recognized in AOCIAOCL for the cash flow hedges for the three and nine months ended September 30, 2017 and 2016:March 31, 2020:
  Three months ended Three months ended
  September 30, 2017 September 30, 2016
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gains in AOCI $3.0
 $1.4
 $3.4
 $1.6
Net gains associated with current period hedging transactions 1.3
 0.1
 9.5
 —
Net gains / (losses) reclassified to earnings        
Interest expense —
 (0.2) —
 (0.2)
Revenues (2.7) —
 (6.0) —
Purchased power 0.5
 —
 0.6
 —
Ending accumulated derivative gains in AOCI $2.1
 $1.3
 $7.5
 $1.4
         
  Nine months ended Nine months ended
  September 30, 2017 September 30, 2016
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gains / (losses) in AOCI $(4.3) $1.6
 $9.2
 $2.0
Net gains associated with current period hedging transactions 11.9
 0.2
 22.5
 —
Net gains / (losses) reclassified to earnings        
Interest expense —
 (0.5) —
 (0.6)
Revenues (8.1) —
 (30.1) —
Purchased power 2.6
 —
 5.9
 —
Ending accumulated derivative gains in AOCI $2.1
 $1.3
 $7.5
 $1.4
         
Portion expected to be reclassified to earnings in the next twelve months (a)
 $1.5
 $(0.4)    
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 6
 37
    

(a)The actual amounts that we reclassify from AOCI
Three months ended
March 31, 2020
Interest
$ in millions (net of tax)Rate Hedge
Beginning accumulated derivative losses in AOCL$(0.4)
Net losses associated with current period hedging transactions(0.3)
Net gains reclassified to earnings related to power can differ from the estimate above due to market price changes.
Interest expense(0.1)
Ending accumulated derivative losses in AOCL$(0.8)

Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.

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 purchase and normal sales scope exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Statements of Operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty. FTRs, natural gas futures, and certain forward power contracts are currently marked to market.

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



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Financial Statement Effect
The following tables present the amount and classification within the Condensed Statements of Operations of the gains and losses on DP&L's derivatives not designated as hedging instruments for the three and nine months ended September 30, 2017 and 2016:
For the three months ended September 30, 2017
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $0.2
 $(1.4) $—
 $(1.2)
Realized gain / (loss) 0.2
 1.9
 (0.2) 1.9
Total $0.4
 $0.5
 $(0.2) $0.7
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $3.3
 $—
 $3.3
Purchased power 0.4
 (2.8) (0.2) (2.6)
Total $0.4
 $0.5
 $(0.2) $0.7
         
For the three months ended September 30, 2016
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $—
 $1.2
 $(0.3) $0.9
Realized gain / (loss) (0.1) (2.4) 0.2
 (2.3)
Total $(0.1) $(1.2) $(0.1) $(1.4)
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $(10.4) $—
 $(10.4)
Purchased power (0.1) 9.2
 (0.1) 9.0
Total $(0.1) $(1.2) $(0.1) $(1.4)
         
For the nine months ended September 30, 2017
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $(0.5) $2.2
 $(0.8) $0.9
Realized gain / (loss) 0.5
 (1.5) (0.3) (1.3)
Total $—
 $0.7
 $(1.1) $(0.4)
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $(2.7) $—
 $(2.7)
Purchased power —
 3.4
 (1.1) 2.3
Total $—
 $0.7
 $(1.1) $(0.4)
         
For the nine months ended September 30, 2016
$ in millions FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $0.4
 $2.3
 $—
 $2.7
Realized gain / (loss) (0.4) (5.3) 0.7
 (5.0)
Total $—
 $(3.0) $0.7
 $(2.3)
  
 
 
 
Recorded in Income Statement: gain / (loss)        
Revenues $—
 $(13.1) $—
 $(13.1)
Purchased power —
 10.1
 0.7
 10.8
Total $—
 $(3.0) $0.7
 $(2.3)

DP&L has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.



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The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged, as well as the fair value, balance sheet classification and hedging designation of DP&L’s derivative instruments:
Fair Values of Derivative Instruments
at September 30, 2017
      Gross Amounts Not Offset in the Condensed Balance Sheets  
$ in millions Hedging Designation 
Gross Fair Value as presented in the Balance Sheets (a)
 Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Fair Value
Assets          
Short-term derivative positions (presented in Other prepayments and current assets)
Forward power contracts Designated $7.0
 $(4.6) $—
 $2.4
Forward power contracts Not designated 3.5
 (2.7) —
 0.8
Natural gas futures Not designated —
 —
 —
 —
           
Long-term derivative positions (presented in Other deferred assets)
Interest rate swap Designated 0.9
 —
 —
 0.9
Natural gas futures Not designated —
 —
 —
 —
Forward power contracts Not designated 0.3
 —
 —
 0.3
Total assets   $11.7
 $(7.3) $—
 $4.4
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts Designated $4.6
 $(4.6) $—
 $—
Interest rate swaps Designated —
 —
 —
 —
Forward power contracts Not designated 3.5
 (2.7) (0.7) 0.1
Natural gas futures Not designated 0.8
 —
 (0.8) —
FTRs Not designated 0.5
 —
 —
 0.5
           
Long-term derivative positions (presented in Other deferred credits)
Natural gas futures Not designated —
 —
 —
 —
Total liabilities   $9.4
 $(7.3) $(1.5) $0.6

(a)    includes credit valuation adjustment



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Fair Values of Derivative Instruments
at December 31, 2016
      Gross Amounts Not Offset in the Condensed Balance Sheets  
$ in millions Hedging Designation 
Gross Fair Value as presented in the Balance Sheets (a)
 Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Fair Value
Assets          
Short-term derivative positions (presented in Other prepayments and 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)
Forward power contracts Designated $16.4
 $(10.5) $(5.5) $0.4
Interest rate swaps Designated 0.7
 —
 —
 0.7
Forward power contracts Not designated 7.7
 (4.7) —
 3.0
           
Long-term derivative positions (presented in Other deferred credits)
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

Credit risk-related contingent features
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at September 30, 2017 was $9.4 million. $1.5 million of collateral was 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 $7.3 million. If DP&L's long-term debt were to fall below investment grade, DP&L could be required to post collateral for the remaining $0.6 million.



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Note 76 – Long-term Debt


The following table summarizes DP&L's outstandingAES Ohio's long-term debt.
InterestMarch 31,December 31,
$ in millionsRateMaturity20212020
First Mortgage Bonds3.95 %2049$425.0 $425.0 
First Mortgage Bonds3.20 %2040140.0 140.0 
U.S. Government note4.20 %206117.3 17.4 
Unamortized deferred financing costs(5.5)(5.7)
Unamortized debt discounts, net(2.6)(2.6)
Total long-term debt574.2 574.1 
Less: current portion(0.2)(0.2)
Long-term debt, net of current portion$574.0 $573.9 
  Interest   September 30, December 31,
$ in millions Rate Maturity 2017 2016
Term loan - rates from 4.01% - 4.49% (a) and 4.00% - 4.01% (b)   2022 $441.7
 $445.0
Tax-exempt First Mortgage Bonds 4.8% 2036 —
 100.0
Tax-exempt First Mortgage Bonds - rates from 1.52% - 1.83% (a) and 1.29% - 1.42% (b)   2020 200.0
 200.0
U.S. Government note 4.2% 2061 17.9
 18.0
Capital leases     0.3
 0.4
Unamortized deferred financing costs     (9.9) (11.8)
Unamortized long-term debt discounts     (2.0) (2.2)
Total long-term debt     648.0
 749.4
Less: current portion     (4.7) (4.7)
Long-term debt, net of current portion     $643.3
 $744.7

(a)Range of interest rates for the nine months ended September 30, 2017.
(b)Range of interest rates for the year ended December 31, 2016.

Deferred financing costs are amortized over the remaining life of the debt using the effective interest method. Premiums or discounts on long-term debt are amortized over the remaining life of the debt using the effective interest method.


Line of credit
At September 30, 2017, DP&LMarch 31, 2021 and December 31, 2020, AES Ohio had $15.0 million in outstanding borrowings on its line of credit.credit of $80.0 million and $20.0 million, respectively.

Significant transactions
On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of defeased bonds was completed on October 30, 2017.


Long-term debt covenants and restrictions
DP&L’sAES Ohio's unsecured revolving credit agreementfacility and Bond Purchase and Covenants Agreement have two(financing document entered into in connection with the issuance of AES Ohio's First Mortgage Bonds, on July 31, 2020) has one financial covenants.covenant. The firstcovenant 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 ratio compares EBITDA to Interest Expense and is calculated at the end of each fiscal quarter by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

On 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 (which is used for measuring the AES Ohio’s Total Debt to Total Capitalization ratio under eachshall not be greater than 0.67 to 1.00. As of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets2021, AES Ohio was inDP&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 September 30, 2017 is 0.46 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if DP&L's long-term indebtedness, as required by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.this financial covenant.



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As of September 30, 2017, DP&LMarch 31, 2021, AES Ohio was in compliance with all debt covenants, including the financial covenants described above.


The cost of borrowing under DP&L's unsecured revolving credit agreement and Bond Purchase and Covenants Agreement adjusts under certain credit rating scenarios.AES Ohio does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.


Substantially all property, plant & equipment of DP&LAES Ohio is subject to the lien of the mortgage securing DP&L’sAES Ohio’s First and Refunding Mortgage. In July 2017, assets related to the Miami Fort station and the Zimmer station were released from the lien of DP&L's First and Refunding Mortgage in connection with the pending sale. On October 1, 2017, all the other DP&L generation assets transferred to AES Ohio Generation as part of Generation Separation were released from the lien of DP&L’s First and Refunding Mortgage. See Note 13 – Assets and Liabilities Held for Sale for additional information.


Note 87 – Income Taxes


The following table details the effective tax rates for the three and nine months ended September 30, 2017March 31, 2021 and 2016.2020.
Three months ended
March 31,
20212020
AES Ohio14.9%9.3%

39
  Three months ended Nine months ended
  September 30, September 30,
  2017 2016 2017 2016
DP&L 28.9% 39.6% 5.3% 36.7%

Income tax expense for the nine months ended September 30, 2017AES Ohio’s effective combined state and 2016 was calculated using the estimated annual effectivefederal income tax rates for 2017 and 2016 of 19.0% and 36.7%, respectively. Management estimates the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the estimated rates could be materially different from the actual effective tax rates. The effective tax ratewas 14.9% for the three months ended September 30, 2017 includesMarch 31, 2021. This is different from the impactcombined federal and state statutory rate of an adjustment relating to flow-through depreciation. The impact of this adjustment increased the effective tax rate by 8.2% for the three months ended September 30, 2017. There is no impact on the effective tax rate for the nine months ended September 30, 2017.

The decrease in the annual effective rate compared to the same period in 2016 is22.5% primarily due to the forecastednet tax expense relatingbenefit related to flow-through depreciation and the projected manufacturer's production deduction.reversal of excess deferred taxes.


Income taxes paid, net, were $22.2 million and $0.3 million for the nine months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017, the $22.2 million represented payments made to DPL.

Note 98 – Benefit Plans


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


We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were $5.0$9.8 million and $7.5 million in employer contributions during each of the ninethree months ended September 30, 2017March 31, 2021 and 2016.2020, respectively.


The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The pension costs below have not been adjusted for amounts billed to the Service Company for former DP&LAES Ohio employees who are now employed by the Service Company butor for amounts billed to AES Ohio Generation for former employees that were employed by AES Ohio Generation that are still participants in the DP&LAES Ohio plan.



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The net periodic benefit cost of the pension benefit plans for the three and nine months ended September 30, 2017March 31, 2021 and 20162020 was:
Three months ended
March 31,
$ in millions20212020
Service cost$1.1 $0.9 
Interest cost2.0 3.0 
Expected return on plan assets(3.7)(4.7)
Amortization of unrecognized:
Prior service cost0.3 0.3 
Actuarial loss2.8 2.2 
Net periodic benefit cost$2.5 $1.7 
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Service cost $1.5
 $1.4
 $4.3
 $4.2
Interest cost 3.5
 3.7
 10.6
 11.1
Expected return on plan assets (5.7) (5.7) (17.1) (17.1)
Plan curtailment (a)
 —
 —
 5.6
 —
Amortization of unrecognized:        
Prior service cost 0.3
 0.8
 1.1
 2.3
Actuarial loss 2.1
 1.8
 6.6
 5.4
Net periodic benefit cost $1.7
 $2.0
 $11.1
 $5.9


(a)
As a result of the decision to retire certain of DP&L's coal-fired plants, we recognized a plan curtailment of $5.6 million in the first quarter of 2017. See Note 14 – Fixed-asset Impairments for more information.

In addition, DP&LAES Ohio provides postretirement health care and life insurance benefits to certain retired employees, their spouses and eligible dependents. 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 $15.6$8.8 million at September 30, 2017March 31, 2021 and $15.8$9.0 million at December 31, 20162020 were not material to the financial statements in the periods covered by this report.


Benefit payments, which reflect future service, are estimated to be paid as follows:
$ in millions  
Estimated to be paid during Pension
2017 $6.3
2018 $25.5
2019 $26.0
2020 $26.4
2021 $26.7
2022 - 2026 $139.6

Note 109 – Shareholder’sShareholder's Equity


DP&L has 250,000,000 authorized sharesReturns of common stock, $0.01 par value, of which 41,172,173 are outstanding at September 30, 2017. All common shares are held by DP&L’s parent, DPL.Capital

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio, calculated as total equity divided by total capitalization, of at least 50 percent and to not have a negative retained earnings balance. After the fixed-asset impairments recorded in 2017 and 2016 and as of September 30, 2017, DP&L's equity ratio was 39% and retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L. 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. After considering the payments and defeasance noted in Note 7 – Long-term Debt, DP&L's long-term debt is $659.9 million.

During the ninethree months ended September 30, 2017, DP&L paid $19.0 million in cash to DPL, which was treated as aMarch 31, 2021, AES Ohio made return of capital reducing Other paid-in capital. In addition, DPL made a $70.0payments of $10.0 million to DPL. AES Ohio did not make any return of capital contributionpayments to DP&L duringDPL for the third quarter of 2017.three months ended March 31, 2020.


Note 1110 – Contractual Obligations, Commercial Commitments and Contingencies


Equity Ownership Interest
DP&LAES Ohio has a 4.9% equity ownership interest in OVEC, which is recorded using the cost method of accounting under GAAP. AES Ohio, along with several non-affiliated energy companies party to an OVEC arrangement, receive and pay for OVEC capacity and energy and are responsible for OVEC debt obligations and other fixed costs in proportion to their power participation ratios under the arrangement, which, for AES Ohio, is the same as its equity ownership interest. At September 30, 2017, DP&LMarch 31, 2021, AES Ohio could be responsible for the repayment of 4.9%, or $71.3$62.0 million, of a $1,455.5$1,264.5 million OVEC debt obligationobligations if they came due, comprised of both fixed and variable rate securities with maturities from 20192022 to


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2040. OVEC could also seek additional contributions from usAES Ohio to avoid a default in the event that other OVEC members defaulted on their respective OVEC obligations. As of September 30, 2017, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations
There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Form 10-K for the fiscal year ended December 31, 2016.


Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Financial
40
Statements, as prescribed by GAAP, are adequate in light ofconsidering the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2017,March 31, 2021, cannot be reasonably determined.


Environmental Matters
DP&L’sAES Ohio’s current and previously-owned 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 State Implementation Plans) 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 change;changes;
•
Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will 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, the Ohio EPA or other authorities that require or will require substantial reductions in SO2, particulates, mercury, acid gases, NOx and other air emissions;
•Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs;
•Rules and future rules issued by the USEPA, the Ohio EPA or other authorities 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 consists of 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 ofseveral 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 orand cash flows.


We have several pending environmental matters associated
Note 11 – Revenue

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. For further discussion of our Retail, Wholesale, RTO ancillary, and Capacity revenues, see Note 13 — Revenue in Item 8.—Financial Statements and Supplementary Data of our Form 10-K.

AES Ohio's revenue from contracts with our coal-fired generation units. Some of these matters could have material adverse impacts oncustomers was $169.7 million and $164.8 million for the operation of the power stations.


three months ended March 31, 2021 and 2020, respectively.

41
66


The following table presents our revenue from contracts with customers and other revenue for the three months ended March 31, 2021 and 2020:
Three months ended
March 31,
$ in millions20212020
Retail revenue
Retail revenue from contracts with customers
Residential revenue$98.3 $96.9 
Commercial revenue27.3 28.9 
Industrial revenue12.3 11.8 
Governmental revenue7.4 9.3 
Other (a)
3.7 3.3 
Total retail revenue from contracts with customers149.0 150.2 
Other retail revenue (b)
0 3.3 
Wholesale revenue
Wholesale revenue from contracts with customers5.0 2.7 
RTO ancillary revenue14.8 10.7 
Capacity revenue0.9 1.2 
Miscellaneous revenue3.1 0.9 
Total revenues$172.8 $169.0 

(a)    "Other" primarily includes Wright-Patterson Air Force Base revenues, billing service fees from CRES providers and other miscellaneous retail revenues from contracts with customers.
(b)    Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606.

The balances of receivables from contracts with customers were $60.1 million and $69.2 million as of March 31, 2021 and December 31, 2020, respectively. Payment terms for all receivables from contracts with customers are typically within 30 days.

Note – 12 Risks and Uncertainties

COVID-19 Pandemic

The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility and negative pressure in financial markets. The global impact of the outbreak has been rapidly evolving and many countries, including the U.S., have reacted by instituting quarantines, mandating business and school closures and social distancing measures as well as restricting travel. Responses to the COVID-19 pandemic by the State of Ohio and its residents and businesses, in particular, continue to evolve, including with respect to business and school closures and limitations and other social distancing measures and the effectiveness and timing of vaccine availability and distribution efforts. Social distancing measures designed to slow the spread of the virus, such as business closures and operations limitations, impact energy demand within our service territory. We are taking a variety of measures in response to the spread of COVID-19 to ensure our ability to transmit, distribute and sell electric energy, ensure the health and safety of our employees, contractors, customers and communities and provide essential services to the communities in which we operate. In addition to the impacts to demand within our service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, including those that relate to events outside of our control. The magnitude and duration of the COVID-19 pandemic is unknown at this time and may have material and adverse effects on our results of operations, financial condition and cash flows in future periods.

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Note 12 – Business Segments

Through September 30, 2017, DP&L managed the business through two reportable operating segments, the T&D segment and the Generation segment. After Generation Separation, DP&L will have only one reportable operating segment, the T&D segment, beginning on October 1, 2017. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that this measure 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 520,000 retail customers 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 recording 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 did not transfer to AES Ohio Generation on October 1, 2017 when DP&L’s generation separation occurred, 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 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. Through September 30, 2017, DP&L owned multiple coal-fired and peaking electric generating facilities. As a result of Generation Separation, the DP&L-owned generating facilities were transferred to AES Ohio Generation on October 1, 2017, and DP&L will no longer have a Generation segment.

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, costs of sales and expenses 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
Three months ended September 30, 2017
Revenues from external customers $184.2
 $121.4
 $—
 $305.6
Intersegment revenues —
 —
 —
 —
Total revenues $184.2
 $121.4
 $—
 $305.6
         
Depreciation and amortization $19.6
 $3.1
 $—
 $22.7
Interest expense $7.7
 $—
 $—
 $7.7
Income from operations before income tax $20.0
 $21.2
 $—
 $41.2
         
Cash capital expenditures $20.6
 $4.2
 $—
 $24.8



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$ in millions T&D Generation Adjustments and Eliminations 
DP&L Total
Three months ended September 30, 2016
Revenues from external customers $215.8
 $152.6
 $—
 $368.4
Intersegment revenues —
 —
 —
 —
Total revenues $215.8
 $152.6
 $—
 $368.4
         
Depreciation and amortization $17.8
 $6.3
 $—
 $24.1
Interest expense $6.4
 $0.1
 $—
 $6.5
Income from operations before income tax $36.5
 $13.3
 $—
 $49.8
         
Cash capital expenditures $19.6
 $6.9
 $—
 $26.5

$ in millions T&D Generation Adjustments and Eliminations DP&L Total
Nine months ended September 30, 2017
Revenues from external customers $542.5
 $358.3
 $—
 $900.8
Intersegment revenues —
 —
 —
 —
Total revenues $542.5
 $358.3
 $—
 $900.8
         
Depreciation and amortization $56.3
 $11.9
 $—
 $68.2
Fixed-asset Impairments (Note 14) $—
 $66.3
 $—
 $66.3
Interest expense $22.9
 $0.2
 $—
 $23.1
Income / (loss) from operations before income tax $60.1
 $(56.3) $—
 $3.8
         
Cash capital expenditures $66.3
 $16.1
 $—
 $82.4
         
At September 30, 2017        
Total assets $1,655.3
 $178.0
 $—
 $1,833.3

$ in millions T&D Generation Adjustments and Eliminations 
DP&L Total
Nine months ended September 30, 2016
Revenues from external customers $605.4
 $425.9
 $—
 $1,031.3
Intersegment revenues —
 —
 —
 —
Total revenues $605.4
 $425.9
 $—
 $1,031.3
         
Depreciation and amortization $55.1
 $40.1
 $—
 $95.2
Fixed-asset Impairments (Note 14) $—
 $857.1
 $—
 $857.1
Interest expense $16.9
 $0.3
 $—
 $17.2
Income / (loss) from operations before income tax $98.5
 $(837.9) $—
 $(739.4)
         
Cash capital expenditures $61.8
 $36.5
 $—
 $98.3
         
At December 31, 2016        
Total assets $1,710.5
 $324.6
 $—
 $2,035.1

Note 13 – Assets and Liabilities Held for Sale

On April 21, 2017, DP&L and AES Ohio Generation entered into an Asset Purchase Agreement with subsidiaries of Dynegy Inc., for the sale of DP&L's undivided interests in the Zimmer Station and the Miami Fort Station for cash and the assumption of certain liabilities, including environmental liabilities. The cash purchase price is subject to


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adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs prior to closing. The sale is subject to approval by the FERC and is expected to close in the fourth quarter of 2017.

Accordingly, the assets and liabilities of Zimmer Station and Miami Fort Station were classified as held for sale as of September 30, 2017, but the plants did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities classified as held for sale as of September 30, 2017:
$ in millions September 30, 2017
Assets  
Accounts receivable, net (a)
 $(11.2)
Inventories 22.7
Property, plant & equipment, net 44.8
Other prepayments and current assets 0.7
Total assets of the disposal group classified as held for sale in the balance sheet $57.0
   
Liabilities  
Accounts payable $0.7
Accrued taxes 2.6
Asset retirement obligations 3.4
Other liabilities (b)
 (0.7)
Total liabilities of the disposal group classified as held for sale in the balance sheet $6.0

(a)Represents credit balances netted in Accounts Receivable, due to the right of offset with partners
(b)Represents amounts due to (from) partners for pension benefits associated with partner-operated plants

Zimmer Station and Miami Fort Station's results are reflected within continuing operations in the Condensed Statements of Operations. The combined income / (loss) from continuing operations before income tax for Zimmer Station and Miami Fort Station was $11.0 million and $1.9 million for the three months ended September 30, 2017 and 2016, respectively, and $18.9 million and $(333.5) million for the nine months ended September 30, 2017 and 2016, respectively. Zimmer Station and Miami Fort Station are included in the Generation segment.

Note 14 – Fixed-asset Impairments

On March 17, 2017, the Board of Directors of DP&L approved the retirement of the two DP&L operated and co-owned electric generating stations; the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. We performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart Station and Killen Station were determined to have fair values of $3.3 million and $7.9 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively.

Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal of $9.8 million and $6.4 million for Stuart Station and Killen Station inventories, respectively, during the first quarter of 2017, which is recorded in Loss on asset disposal in the Condensed Statements of Operations.

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 amount of the asset groups of Stuart, Killen and Zimmer were not recoverable. The asset groups of Stuart, Killen and Zimmer were determined to have fair values of $164.4 million, $84.3 million and $111.0 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $292.0 million, $246.2 million and $318.9 million for Stuart, Killen and Zimmer, respectively.



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Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations


This report includes the combined filing of DPL and DP&L.AES Ohio. AES Ohio is a wholly-owned subsidiary of DPL and is a public utility incorporated in 1911 under the laws of Ohio. On November 28, 2011, DPL became an indirectly 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&LAES Ohio, respectively and together, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&LAES Ohio will clearly be noted in the section.


FORWARD-LOOKING INFORMATION
The following discussion contains forward-looking statements and should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes of DPL and the Condensed Financial Statements and related footnotes of DP&LAES Ohio included in Part I – Financial Information,, the risk factors in Item 1A to Part I of our Form 10-K for the fiscal year ended December 31, 2016 and2020, in Part II, Item 1A to Part II of this Quarterly Report on Form 10-Q and our “Forward-Looking Statements” section of this Form 10-Q. For a list of certain abbreviations or acronyms in this discussion, see the Glossary at the beginning of this Form 10-Q.


Key topicsOVERVIEW OF OUR BUSINESS
DPL is an indirectly wholly-owned subsidiary of AES.

DP&L, a wholly-owned subsidiary of DPL that does business as AES Ohio, 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, retail transmission and distribution services are still regulated. AES Ohio has the exclusive right to provide such transmission and distribution services to approximately 532,000 customers located in West Central Ohio. Additionally, AES Ohio provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000-square mile area of West Central Ohio.

DPL’s other primary subsidiaries are MVIC and Miami Valley Lighting. MVIC is our captive insurance company that provides insurance services to AES Ohio and our other subsidiaries, and Miami Valley Lighting provides street and outdoor lighting services to customers in the Dayton region. For additional information, see Item 1 – Business of our Form 10-K. All of DPL's subsidiaries are wholly-owned.

As an electric public utility in Ohio, AES Ohio provides regulated transmission and distribution services to its customers as well as retail SSO electric service. AES Ohio's sales reflect the general economic conditions, seasonal weather patterns and the growth of energy efficiency initiatives.

EXECUTIVE SUMMARY

DPL
Compared with the prior year, DPL's net income from continuing operations before income taxes was higher by $11.5 million, or 479% for the three months ended March 31, 2021, primarily due to factors including, but not limited to:
Three months ended
March 31,
$ in millions2021 vs. 2020
Net increase in the volume of retail kWh sold primarily driven by favorable weather, partially offset by the purchased power volume variance$3.7 
Higher RTO ancillary revenues due to increase in transmission rates4.2 
Increase due to lower interest expense from debt refinancings in the prior year3.3 
Other0.3 
Net change in income from continuing operations before income tax$11.5

43
AES Ohio
Compared with the prior year, AES Ohio's net income from continuing operations before income taxes was higher by $8.6 million, or 67% for the three months ended March 31, 2021, primarily due to factors including, but not limited to:
Three months ended
March 31,
$ in millions2021 vs. 2020
Net increase in the volume of retail kWh sold primarily driven by favorable weather, partially offset by the purchased power volume variance$3.7 
Higher RTO ancillary revenues due to increase in transmission rates4.2 
Other0.7 
Net change in income before income tax$8.6
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RESULTS OF OPERATIONS HIGHLIGHTS – DPL

DPL’s results of operations include the results of its subsidiaries, including its principal subsidiary AES Ohio. All material intercompany accounts and transactions have been eliminated in consolidation. A separate discussion of the results of operations for AES Ohio is presented elsewhere in this report.
Three months ended
March 31,
$ in millions20212020$ change% change
Revenues:
Retail$149.0 $153.5 $(4.5)(3)%
Wholesale4.8 2.5 2.3 92%
RTO ancillary14.9 10.7 4.2 39%
Capacity revenues0.9 1.2 (0.3)(25)%
Miscellaneous revenues5.6 3.3 2.3 70%
Total revenues175.2 171.2 4.0 2%
Operating costs and expenses
Net fuel cost0.4 0.6 (0.2)(33)%
Purchased power:
Purchased power61.0 57.4 3.6 6%
RTO charges10.5 5.4 5.1 94%
Net purchased power cost71.5 62.8 8.7 14%
Operation and maintenance34.9 47.1 (12.2)(26)%
Depreciation and amortization19.1 17.7 1.4 8%
Taxes other than income taxes20.4 20.9 (0.5)(2)%
Other, net(0.1)(0.1)— —%
Total operating costs and expenses146.2 149.0 (2.8)(2)%
Operating income29.0 22.2 6.8 31%
Other income / (expense), net:
Interest expense(15.6)(18.9)3.3 (17)%
Other income / (expense)0.5 (0.9)1.4 (156)%
Total other expense, net(15.1)(19.8)4.7 (24)%
Income from continuing operations before income tax (a)$13.9 $2.4 $11.5 479%

(a)For purposes of discussing operating results, we present and discuss Income 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.

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DPL – Revenues
Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, our retail sales demand 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. Additionally, our retail revenues are affected by regulated rates and riders including the changes to our ESP described in Note 3 - Regulatory Matters of our Form 10-K and Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements.
HEATING AND COOLING DEGREE-DAYS (a)
Three months ended
March 31,
20212020change% change
Actual
Heating degree-days2,677 2,337 340 15 %
Cooling degree-days— — — — %
30-year average (b)
Heating degree-days2,833 2,833 
Cooling degree-days2 2 

(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 degrees that the average actual daily temperature is 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. Similarly, cooling degrees in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.
(b)30-year average is computed from observed degree-days in the Dayton area on a trailing 30-year basis.

DPL's and AES Ohio's electric sales and billed customers were as follows:
ELECTRIC SALES AND CUSTOMERS (a)
Three months ended
March 31,
20212020change% change
Retail electric sales (b)
Residential1,530 1,398 132 9 %
Commercial834 855 (21)(2)%
Industrial866 894 (28)(3)%
Governmental279 291 (12)(4)%
Other5 5 — — %
Total retail electric sales3,514 3,443 71 2 %
Wholesale electric sales (c)
146 119 27 23 %
Total electric sales3,660 3,562 98 3 %
Billed electric customers (end of period)531,669 527,058 4,611 1 %

(a)Electric sales are presented in millions of kWh.
(b)DPL and AES Ohio retail electric sales represent the total transmission and distribution retail sales for the periods presented. SSO sales were 1,070 kWh and 1,015 kWh for the three months ended March 31, 2021 and 2020, respectively.
(c)Wholesale electric sales are AES Ohio's 4.9% share of the generation output of OVEC.
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The following graph shows the percentage changes in weather-normalized and actual retail electric sales volumes by customer class for the three months ended March 31, 2021 as compared to the same period in the prior year:
dpl-20210331_g2.jpg


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During the three months ended March 31, 2021, Revenues increased $4.0 million to $175.2 million compared to $171.2 million in the same period of the prior year. This change was primarily the result of changes in the components of revenue shown below:
Three months ended
March 31,
$ in millions2021 vs. 2020
Retail
Rate
Decrease in Energy Efficiency and USF Revenue Rate Riders$(10.5)
Decrease in Competitive Bid Revenue Rate Rider (Standard Offer Rate)(5.5)
Decrease due to deferred storm charges(2.1)
Increase due to the TCRR Rider5.1 
Other0.6 
Net change in retail rate(12.4)
Volume
Net increase in the volume of kWh sold primarily due to favorable weather compared to the same period in the prior year, partially offset by a decrease in demand due to the impacts of the COVID-19 pandemic7.6 
Other miscellaneous0.3 
Total retail change(4.5)
Wholesale
Increase due to higher wholesale prices and higher volumes at OVEC2.3
RTO ancillary and capacity revenues
Increase primarily due to higher transmission rates as a result of changing from a stated rate to a formula rate in May 20203.9
Miscellaneous revenues
Increase due to collections on Legacy Generation Rider2.3
Net change in revenues$4.0

DPL – Net Purchased Power
During the three months ended March 31, 2021, Net purchased power increased $8.7 million to $71.5 million compared to $62.8 million in the same period of the prior year. This change was primarily the result of changes in the cost of purchased power shown below.
Three months ended
March 31,
$ in millions2021 vs. 2020
Net purchased power
Purchased power
Rate
Decrease due to pricing in the competitive bid process$(0.3)
Volume
Increase due to higher retail load served primarily driven by weather3.9 
Total purchased power change3.6 
RTO charges
Increase primarily due to higher TCRR rates5.1 
Net change in purchased power$8.7

48
DPL – Operation and Maintenance
During the three months ended March 31, 2021, Operation and maintenance expense decreased $12.2 million compared to the same period in the prior year. The main drivers of this change are as follows:
Three months ended
March 31,
$ in millions2021 vs. 2020
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF Revenue Rate Rider (a)
$(4.3)
Decrease in Alternative Energy and Energy Efficiency programs (a)
(4.0)
Decrease in deferred storm costs (a)
(2.0)
Other, net(1.9)
Net change in operation and maintenance expense$(12.2)

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

DPL – Depreciation and Amortization
During the three months ended March 31, 2021, Depreciation and amortization increased $1.4 million compared to the same period in the prior year. The increase was primarily the result of higher depreciable property, plant and equipment balances in the current year.

DPL – Interest Expense
During the three months ended March 31, 2021, Interest expense decreased $3.3 million compared to the same period in the prior year. The decrease was primarily the result of the refinancing of debt at DPL in 2020.

DPL – Other Income / (Expense)
During the three months ended March 31, 2021, Other income / (expense) increased $1.4 million compared to the same period in the prior year. The increase was primarily the result of unrealized losses on AES Ohio's Master Trust assets in the prior year due to decreased fair value of investments.

DPL – Income Tax Benefit From Continuing Operations
Income tax benefit was $0.3 million during the three months ended March 30, 2021 compared to a benefit of $0.1 during the three months ended March 31, 2020.

See Note 7 – Income Taxes in the Notes to DPL's Condensed Consolidated Financial Statements for further discussion.

DPL – Discontinued Operations
Net loss from discontinued operations was $(0.6) million for the three months ended March 31, 2021 and March 31, 2020. This loss relates to the generation components of Stuart and Killen, which were retired in 2018 and sold in 2019, and Conesville, which was retired in May 2020 and sold in June 2020. See Part I, Item 1, Note 12 – Discontinued Operations in the Notes to DPL's Condensed Consolidated Financial Statements for further discussion.

RESULTS OF OPERATIONS BY SEGMENT - DPL

DPL manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure 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 segment. The Utility segment is discussed further below.

Utility Segment
The Utility segment is comprised of AES Ohio’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. AES Ohio distributes electricity to approximately 532,000 retail customers located in a 6,000-square mile area of West Central Ohio. AES Ohio’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, AES Ohio applies the accounting standards for regulated operations to its electric transmission and distribution businesses recording regulatory assets when incurred costs are expected to be recovered in future
49
customer rates and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The Utility segment includes revenues and costs associated with our investment in OVEC and the historical results of AES Ohio’s Hutchings Coal Station, which was closed in 2013 and transferred to a third party in the fourth quarter of 2020.

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 long-term debt as well as adjustments related to purchase accounting from the Merger. The accounting policies of the reportable segment are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies of our 10-K. Intersegment sales, costs of sales and expenses are eliminated in consolidation. Certain shared and corporate costs are allocated between "Other" and the Utility reporting segment.

See Part I, Item 1, Note 10 – Business Segments of Notes to DPL's Condensed Consolidated Financial Statements for additional information regarding DPL’s reportable segment.

The following table presents DPL’s Income / (loss) from continuing operations before income tax by business segment:
Three months ended
March 31,
$ in millions20212020
Utility$21.5 $12.9 
Other(7.6)(10.5)
Income from continuing operations before income tax (a)$13.9 $2.4 

(a)For purposes of discussing operating results, we present and discuss Income 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.

RESULTS OF OPERATIONS HIGHLIGHTS – DPL – Utility Segment

The results of operations of the Utility segment for DPL are identical in all material respects and for all periods presented to those of AES Ohio, which are included in Part I, Item 2, Management's Discussion and Analysis

Our discussion covers the following:
Review of Financial Condition and Results of Operations (RESULTS OF OPERATIONS HIGHLIGHTS – AES Ohio) of this Form 10-Q.

50
RESULTS OF OPERATIONS HIGHLIGHTS – AES Ohio
Three months ended
March 31,
$ in millions20212020$ change% change
Revenues:
Retail$149.0 $153.5 $(4.5)(3)%
Wholesale5.0 2.7 2.3 85 %
RTO ancillary14.8 10.7 4.1 38 %
Capacity revenues0.9 1.2 (0.3)(25)%
Miscellaneous revenues3.1 0.9 2.2 244 %
Total revenues172.8 169.0 3.8 2 %
Operating costs and expenses
Net fuel cost0.4 0.6 (0.2)(33)%
Purchased power:
Purchased power61.0 57.3 3.7 6 %
RTO charges10.2 5.1 5.1 100 %
Net purchased power cost71.2 62.4 8.8 14 %
Operation and maintenance34.7 47.1 (12.4)(26)%
Depreciation and amortization18.7 17.3 1.4 8 %
Taxes other than income taxes20.3 20.8 (0.5)(2)%
Other, net(0.1)(0.1)— — %
Total operating costs and expenses145.2 148.1 (2.9)(2)%
Operating income27.6 20.9 6.7 32 %
Other income / (expense), net:
Interest expense(6.0)(6.2)0.2 (3)%
Other expense, net(0.1)(1.8)1.7 (94)%
Total other expense, net(6.1)(8.0)1.9 (24)%
Income before income tax (a)$21.5 $12.9 $8.6 67 %

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

AES Ohio – Revenues
Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, our retail sales demand 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. Additionally, our retail revenues are affected by regulated rates and riders including the changes to our ESP described in Note 3 - Regulatory Matters of our Form 10-K and Note 3 – Regulatory Matters of Notes to AES Ohio's Condensed Financial Statements.

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During the three months ended March 31, 2021, Revenues increased $3.8 million to $172.8 million compared to $169.0 million in the same period of the prior year. This change was primarily the result of changes in the components of revenue shown below:
◦DPLThree months ended
March 31,
$ in millions2021 vs. 2020
Retail
▪Rate
DPL - T&D Segment
▪Decrease in Energy Efficiency and USF Revenue Rate Riders
DPL - Generation Segment
$(10.5)
Decrease in Competitive Bid Revenue Rate Rider (Standard Offer Rate)(5.5)
Decrease due to deferred storm charges(2.1)
Increase due to the TCRR Rider5.1 
◦DP&L
▪Other
DP&L - T&D Segment
0.6 
Net change in retail rate(12.4)
▪Volume
DP&L -
Net increase in the volume of kWh sold primarily due to favorable weather compared to the same period in the prior year, partially offset by a decrease in demand due to the impacts of the COVID-19 pandemic7.6 
Other miscellaneous0.3 
Total retail change(4.5)
Wholesale
Increase due to higher wholesale prices and higher volumes at OVEC2.3
RTO ancillary and capacity revenues
Increase primarily due to higher transmission rates as a result of changing from a stated rate to a formula rate in May 20203.8
Miscellaneous revenues
Increase due to collections on Legacy Generation SegmentRider2.2
Net change in revenues$3.8
Key Trends
AES Ohio – Net Purchased Power
During the three months ended March 31, 2021, net purchased power increased $8.8 million to $71.2 million compared to $62.4 million in the same period of the prior year. This change was primarily the result of changes in the cost of purchased power shown below.
Three months ended
March 31,
$ in millions2021 vs. 2020
Net purchased power
Purchased power
Rate
Decrease due to pricing in the competitive bid process$(0.2)
Volume
Increase due to higher retail load served primarily driven by weather3.9 
Total purchased power change3.7 
RTO charges
Increase primarily due to higher TCRR rates5.1 
Net change in purchased power$8.8

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AES Ohio – Operation and UncertaintiesMaintenance
During the three months ended March 31, 2021, Operation and Maintenance expense decreased $12.4 million compared to the same period in the prior year. The main drivers of this change are as follows:
Three months ended
March 31,
$ in millions2021 vs. 2020
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF Revenue Rate Rider (a)
$(4.3)
Decrease in Alternative Energy and Energy Efficiency programs (a)
(4.0)
Decrease in deferred storm costs (a)
(2.0)
Other, net(2.1)
Net change in operation and maintenance expense$(12.4)

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

AES Ohio – Depreciation and Amortization
During the three months ended March 31, 2021, Depreciation and amortization increased $1.4 million compared to the same period in the prior year. The increase was primarily the result of higher depreciable property, plant and equipment balances in the current year.

AES Ohio – Other expense, net
During the three months ended March 31, 2021, Other expense, net decreased $1.7 million compared to the same period in the prior year. The decrease was primarily the result of unrealized losses on AES Ohio's Master Trust assets in the prior year due to decreased fair value of investments.

AES Ohio – Income Tax Expense
Income tax expense was $3.2 million during the three months ended March 31, 2021 compared to $1.2 million during the three months ended March 31, 2020. The increase was primarily due to the higher pre-tax income during the three months ended March 31, 2021.

See Note 7 – Income Taxes of Notes to AES Ohio's Condensed Financial Statements for further discussion.
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KEY TRENDS AND UNCERTAINTIES

During the remainder of 2021 and beyond, we expect our results will be primarily impacted by retail demand and weather. As discussed in Note 3 – Regulatory Mattersof Notes to DPL's Condensed Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to AES Ohio's Condensed Financial Statements in Part I, Item 1 of this report, AES Ohio has requested PUCO approval to defer its decoupling costs consistent with the methodology approved in its DRO. If approved, the deferral would be effective as of December 18, 2019 and going forward would reduce impacts of weather, energy efficiency programs and economic changes in customer demand. In addition, DPL's and AES Ohio's financial results are likely to be driven by other factors including, but not limited to:

•regulatory outcomes;
•the passage of new legislation, implementation of regulations or other changes in regulation; and
•the timely recovery of transmission and distribution expenditures.

COVID-19 Pandemic
The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility and negative pressure in financial markets. Responses to the COVID-19 pandemic by the State of Ohio and its residents and businesses, in particular, continue to evolve, including with respect to business and school closures and limitations and other social distancing measures and the effectiveness and timing of vaccine availability and distribution efforts.

Social distancing measures designed to slow the spread of the virus, such as business closures and operations limitations, impact energy demand within our service industry. In addition to the impacts to demand within our service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, and such expenses may include those that relate to events outside of our control. We experienced impacts from the pandemic in 2020 and into 2021 and expect to continue to experience impacts for the remainder of 2021, and any such impacts during that time or in other future periods could have material and adverse effects on our results of operations, financial condition and cash flows. The following discussion highlights our assessment of the impacts of the COVID-19 pandemic on our current financial and operating status, and our financial and operational outlook based on information known as of this filing. Also see "Item 1A. Risk Factors" to our Form 10-K.

Business Continuity - During the COVID-19 pandemic, we are taking a variety of measures to ensure our ability to generate, transmit, distribute and sell electric energy, to ensure the health and safety of our employees, contractors, customers and communities and to provide essential services to the communities in which we operate. We continue to respond to this global crisis through comprehensive measures to protect our employees and others while fulfilling our vital role in providing our customers with electric energy. While stay-at-home restrictions have been lifted in our service territory, most of our management and administrative personnel are able to work remotely, and we have not experienced significant issues affecting our operations or ability to maintain effective internal controls and produce reliable financial information.

Demand - As the economic impact of the COVID-19 pandemic started to materialize in Ohio in the second half of March 2020 and continued for the duration of 2020 and into 2021, the COVID-19 pandemic primarily impacted our retail sales demand, including for the quarter ended March 31, 2021, as shown by the changes in weather-normalized volumes of kWh sold by customer class as follows:

Customer classFor the three months ended March 31, 2021 compared to the same period in 2020
Residential(1.2)%
Commercial(2.8)%
Industrial(3.1)%
Government and Other(3.9)%

Liquidity - We anticipate continuing to have sufficient liquidity to make all required payments, including payments for salaries and wages owed to our employees, during the COVID-19 pandemic. We also continue to not foresee a significant impact to our access to capital or our liquidity position as a result of the COVID-19 pandemic. For further discussion of our financial condition, liquidity, and capital requirements, see Part I, Item 2 - Management's
54
Discussion and Analysis of Financial Condition and Results of Operations –Capital Resources and Liquidity of this Form 10-Q.
Market
Credit Exposures - We continue to monitor and manage our credit exposures in a prudent manner. During the year ended December 31, 2020, we experienced credit-related impacts from utility customers due to the prohibition of electric utilities, including us, from discontinuing electric utility service to customers through September 1, 2020 and due to the economic impacts of the COVID-19 pandemic, which began to improve in 2021. See Note 2 – Supplemental Financial Information of Notes to DPL's Condensed Consolidated Financial Statements and Note 2 – Supplemental Financial Information or Notes to AES Ohio's Condensed Financial Statements for further discussion of our allowance for credit losses. If these credit-related impacts from the COVID-19 pandemic continue into 2021 or beyond, further deterioration in our credit exposures and customer collections may result. However, as discussed in Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to AES Ohio's Financial Statements in Item 8. - Financial Statements and Supplementary Data of our Form 10-K, AES Ohio’s uncollectible expense is deferred for future collection.

Supply Chain - Our supply chain management has remained robust during this challenging time and we continue to closely manage and monitor developments.

Capital Projects - During the COVID-19 pandemic, our construction projects are proceeding without material delays. For further discussion of our capital requirements, see Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity of this Form 10-Q.

CARES Act - The Coronavirus Aid, Relief, and Economic Security ("CARES") Act was passed by the U.S. Congress and signed into law on March 27, 2020. While we currently expect a limited impact from this legislation on our business, we have deferred the payment of federal payroll taxes in accordance with the provisions of this act. At March 31, 2021, the total deferral was approximately $2.1 million.

See Note 13 – Risks and Uncertainties of Notes to DPL's Condensed Consolidated Financial Statements and Note 12 – Risks and Uncertainties of Notes to AES Ohio's Condensed Financial Statements for more information and Part II, Item 1a - Risk Factors of this Form 10-Q for more information.
Critical Accounting Estimates

Regulatory Environment
REGULATORY ENVIRONMENT

DPL’s, DP&L’sAES Ohio’s and our other subsidiaries’ facilities and operations are subject to a wide range of regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities and operations in an effort to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable and can be reasonably estimated. See Note 10 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DP&L’s Condensed Financial Statements. In addition to matters discussed or updated herein, our Forms2020 Form 10-K and 10-Q previously filed with the SEC during 2017 describe2021 describes other regulatory matters which have not materially changed since that filing. See Part I, Item 1, Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements and Part I, Item 1, Note 3 – Regulatory Matters of Notes to AES Ohio's Condensed Financial Statements for further information regarding regulatory matters.

Distribution Rate Case - On November 30, 2020, AES Ohio filed a new distribution rate case with the PUCO. This rate case proposes a revenue increase of $120.8 million and is pending a commission order.

Stipulation and Recommendation - On October 23, 2020, AES Ohio entered into a Stipulation and Recommendation with the staff of the PUCO and various customers and other organizations, which is subject to PUCO approval. This Stipulation and Recommendation would provide resolution on several matters pending before the PUCO. A hearing was held in January 2021 for consideration of this settlement; a commission order is pending. See additional information in Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to AES Ohio's Condensed Financial Statements.

Ohio House Bill 6 – Legislation was passed, Ohio House Bill 128, that repeals Ohio House Bill 6 provisions related to a nuclear fund and decoupling, effective June 30, 2021. Other provisions from Ohio House Bill 6 currently remain in place, which include the following: beginning January 1, 2020, permitted Ohio utilities, such as AES Ohio, may defer, recover or credit the net proceeds from selling energy and capacity received as part of their interest in OVEC and their OVEC-related costs through a statewide non-bypassable recovery mechanism through 2030; eliminates the annual energy efficiency targets for Ohio utilities after 2020; and allows Ohio utilities to construct customer-sited
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renewable generation for mercantile customers or groups of mercantile customers, the costs of which may only be recovered from those filings.customers. If these provisions from Ohio House Bill 6 are repealed without a replacement with comparable provisions, it could have a material adverse effect on our results of operations, financial condition and cash flows.


ENVIRONMENTAL MATTERSReference Rate Reform

As discussed in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, of our Form 10-K, the UK Financial Conduct Authority announced that it intends to phase out LIBOR by the end of 2021. In the U.S., the Alternative Reference Rate Committee at the Federal Reserve identified the Secured Overnight Financing Rate ("SOFR") as its preferred alternative rate for LIBOR; alternative reference rates in other key markets are under development. On November 30, 2020, the ICE Benchmark Association ("IBA") announced it had begun consultation on its intention to cease publication of two specific LIBOR rates by December 31, 2021, while extending the timeline for the overnight, one-month, three-month, six-month, and 12-month USD LIBOR rates through June 30, 2023. On March 5, 2021, IBA published a feedback statement for the consultation, announcing its intention to cease the publication of these rates on the specified dates. We maintain financial instruments that use LIBOR as an interest rate benchmark. Although the full impact of the reform remains unknown, we have begun to engage with our counterparties to discuss specific action items to be undertaken in order to prepare for amendments when they become due.

Environmental Matters
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 and operations 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 as of September 30, 2017.matters. We also have a number ofseveral 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. Of these, those that we believe are most likely to have a material effect are disclosed in our 2016 10-K. We evaluate the potential liability related to environmental matters quarterly and may revise our accruals.estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition orand cash flows.



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

As a result of DP&L’s decision to retire its Stuart and Killen generating stations, the following environmental regulations and requirements are not expected to have a material impact on DP&L with respect to either of the two generating stations:
water intake regulations finalized by the USEPA on May 19, 2014;
the appeal of the NPDES permit governing the discharge of water from the Stuart station; and
revised technology-based regulations governing water discharges from steam electric generating facilities, finalized by the USEPA on November 3, 2015.

PJM PRICING

Capacity Auction Price
The PJM capacity base residual auction for the 2020/21 period cleared at a per megawatt price of $77/MW-day for our RTO area. The per megawatt prices for the periods 2019/20, 2018/19, 2017/18 and 2016/17 were $100/MW-day, $165/MW-day, $152/MW-day and $134/MW-day, respectively, based on previous auctions. As discussed in our Form 10-K, the CP program, which was previously approved by the FERC, will phase out RPM as of the 2018/19 period. 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 $5.7 million and $4.8 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as our generation capacity and the levels of wholesale revenues. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

OHIO COMPETITION AND REGULATORY PROCEEDINGS

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to provide retail generation service to customers that do not choose an alternative supplier; however, the supply of electricity for DP&L’s SSO customers is all sourced through competitive bid as of January 2016. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

On November 30, 2015, DP&L filed a 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 $65.0 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 rate design, which would increase the monthly customer charge, 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 requires that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. For a discussion of the current status of DP&L's ESPs, please see Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Condensed Financial Statements.

Ohio law and 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. In 2016, DP&L filed a new energy efficiency portfolio plan which was ultimately settled. The settlement agreement extended the current plan and allowed DP&L to continue to collect lost distribution revenues. The settlement agreement was approved by the PUCO in September 2017. On June 15, 2017, DP&L filed a new energy efficiency portfolio plan for programs in years 2018 through 2020. On October 27, 2017, DP&L filed an unopposed Stipulation and Recommendation in that case which expands the programs offered, the overall budget and opportunities for shared savings. Lost distribution revenues will be collected in a new rider established in DP&L's ESP 3. This Stipulation is pending PUCO approval.



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DP&L and AES Ohio Generation filed applications before the FERC to adjust their rates with respect to reactive power provided to PJM from their generation units. On March 3, 2017, DP&L, AES Ohio Generation, and certain intervening parties filed an Offer of Settlement that was approved by the FERC on May 16, 2017. The changes from current reactive power rates were not material. Effective October 1, 2017, FERC approved the transfer of the reactive power rates attributable to generation facilities that had been owned by DP&L to the AES Ohio Generation reactive power tariff. Additionally, the FERC has referred to FERC’s Office of Enforcement for investigation of 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.

Effective October 1, 2017, DP&L completed the separation of its generation assets, which ultimately transferred them to AES Ohio Generation as part of the Generation Separation transactions.



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RESULTS OF OPERATIONS HIGHLIGHTS – DPL

DPL’s results of operations include the results of its subsidiaries, including 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.
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues:        
Retail $163.8
 $197.4
 $487.1
 $553.1
Wholesale 102.2
 138.3
 299.8
 368.0
RTO revenues 15.3
 16.8
 43.7
 47.2
RTO capacity revenues 39.8
 32.9
 106.6
 104.6
Other revenues 2.8
 3.9
 8.7
 8.7
Total revenues 323.9
 389.3
 945.9
 1,081.6
Cost of revenues:        
Fuel cost:        
Fuel 57.6
 80.4
 166.3
 210.9
Gains from the sale of coal (0.3) (1.9) (0.9) (4.9)
Mark-to-market losses —
 0.4
 —
 —
Net fuel cost 57.3
 78.9
 165.4
 206.0
Purchased power:        
Purchased power 63.2
 86.1
 200.4
 254.5
RTO charges 15.8
 23.2
 53.3
 60.2
RTO capacity charges 3.8
 3.6
 10.7
 18.5
Mark-to-market losses / (gains) 1.2
 (1.2) (1.0) (2.7)
Net purchased power cost 84.0
 111.7
 263.4
 330.5
Total cost of revenues 141.3
 190.6
 428.8
 536.5
         
Gross margin 182.6
 198.7
 517.1
 545.1
         
Operating expenses:        
Operation and maintenance 81.9
 91.5
 250.3
 257.2
Depreciation and amortization 27.3
 30.9
 81.8
 100.3
General taxes 20.1
 21.6
 68.3
 64.2
Fixed-asset impairment —
 —
 66.4
 235.5
Loss / (gain) on asset disposal (0.3) —
 15.9
 0.1
Other (5.2) (0.7) (6.1) (0.7)
Total operating expenses 123.8
 143.3
 476.6
 656.6
         
Operating income / (loss) 58.8
 55.4
 40.5
 (111.5)
         
Other income / (expense), net:        
Investment income 0.1
 0.1
 0.2
 0.3
Interest expense (27.2) (27.0) (81.5) (79.3)
Charge for early redemption of debt (3.0) (0.5) (3.3) (3.1)
Other expense (0.7) (0.2) (2.3) (0.9)
Total other expense, net (30.8) (27.6) (86.9) (83.0)
         
Income / (loss) from continuing operations before income tax (a) $28.0
 $27.8
 $(46.4) $(194.5)

(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.


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DPL – Revenues
Retail customers, especially residential and commercial customers, consume more electricity during warmer and colder weather than they do during mild temperatures. Therefore,our retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Cooling degree days typically have a more significant impact than heating degree days since some residential customers do not use electricity to heat their homes.
  Three months ended September 30, Nine months ended September 30,
  2017 2016 2017 2016
Heating degree days (a)
 78
 31
 2,763
 3,212
Cooling degree days (a)
 584
 874
 862
 1,175

(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 degrees that the average actual daily temperature is 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 calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.

We sell generation into the wholesale market which covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; retail demand throughout the entire wholesale market area; availability of our generating plants and non-affiliated generating plants to sell into the wholesale market; contracted wholesale sales and our variable generation costs. Our goal is to make wholesale sales when it is profitable to do so.

The following table provides a summary of changes in revenues compared to the same period in the prior year:

 Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 vs. 2016 2017 vs. 2016
Retail    
Rate $(17.0) $(35.2)
Volume (15.5) (34.1)
Other miscellaneous (1.1) 3.3
Total retail change (33.6) (66.0)
  
 
Wholesale    
Rate (8.8) (25.2)
Volume (27.3) (43.0)
Total wholesale change (36.1) (68.2)
  
 
RTO revenues and RTO capacity revenues    
RTO revenues and RTO capacity revenues 5.4
 (1.5)
  
 
Other    
Other revenues (1.1) —
  
 
Total revenues change $(65.4) $(135.7)

During the three months ended September 30, 2017, Revenues decreased $65.4 million to $323.9 million from $389.3 million in the same period of the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $33.6 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, lower rates associated with the competitive bid rider, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs


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recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as cooling degree days decreased by 290 degree days. The aforementioned impacts resulted in an unfavorable $17.0 million retail price variance and an unfavorable $15.5 million retail volume variance. In addition, there was an unfavorable other miscellaneous variance of $1.1 million.

Wholesale revenues decreased $36.1 million primarily as a result of an unfavorable $27.3 million wholesale volume variance and an unfavorable $8.8 million wholesale price variance. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes of $27.3 million was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 20% decrease in internal generation at DPL's plants in 2017.

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 $5.4 million compared to the same period in the prior year. This increase was the result of a $6.9 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $1.5 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.

During the nine months ended September 30, 2017, Revenues decreased $135.7 million to $945.9 million from $1,081.6 million in the same period of the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $66.0 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 449 degree days and cooling degree days decreased by 313 degree days. The aforementioned impacts resulted in an unfavorable $35.2 million retail price variance and an unfavorable $34.1 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $3.3 million.

Wholesale revenues decreased $68.2 million primarily as a result of an unfavorable $43.0 million wholesale volume variance and an unfavorable $25.2 million wholesale price variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $43.0 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 10% decrease in internal generation at DPL's plants in 2017.

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 $1.5 million compared to the same period in the prior year. This decrease was the result of a $3.5 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves. This decrease was partially offset by a $2.0 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DPL – Cost of Revenues
During the three months ended September 30, 2017, Cost of revenues decreased $49.3 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $21.6 million compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 20% decrease in internal generation.


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Net purchased power decreased $27.7 million compared to the same period in the prior year. This change was driven by the following factors:

◦
Purchased power decreased $22.9 million primarily due to a $11.3 million volume decrease and an $11.6 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016 and lower PJM market rates.

◦
RTO charges decreased $7.4 million compared to the same period in the prior year primarily due to lower transmission and congestion charges. 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 transmission 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 $0.2 million compared to the same period in the prior year primarily due to increases in RTO capacity prices. As noted above, RTO capacity prices are set by an annual auction. The increase in RTO capacity prices was partially offset by a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process.

◦Mark-to-market losses increased $2.4 million due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Cost of revenues decreased $107.7 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $40.6 million compared to the same period in the prior year primarily due to a 13% decrease in average fuel cost per MWh and a 10% decrease in internal generation. There were fuel costs deferred in 2015, which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. There were no fuel costs deferred or collected in the first nine months of 2017.

Net purchased power decreased $67.1 million compared to the same period in the prior year. This decrease was driven by the following factors:

◦
Purchased power decreased $54.1 million primarily due to a $35.8 million volume decrease and an $18.3 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦
RTO charges decreased $6.9 million compared to the same period in the prior year primarily due to lower transmission and congestion charges. 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 transmission 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 $7.8 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.

◦Mark-to-market gains decreased $1.7 million due to changes in power prices in 2017 and 2016.



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DPL – Operation and Maintenance
During the three and nine months ended September 30, 2017, Operation and Maintenance expense decreased $9.6 million and $6.9 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:


Three months ended Nine months ended


September 30, September 30,
$ in millions
2017 vs. 2016 2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)

$(6.3) $(18.4)
Decrease in generating facilities operating and maintenance expenses (6.6) (3.5)
Increase in group insurance expense associated with participation in the AES self-insurance plan
—
 7.3
Increase in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter of 2017
0.8
 6.2
Increase in legal and other consulting costs
1.1
 2.8
Other, net
1.4
 (1.3)
Net change in operation and maintenance expense
$(9.6) $(6.9)

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

DPL – Depreciation and Amortization
During the three months ended September 30, 2017, Depreciation and amortization decreased $3.6 million, compared to the same period in the prior year. The decrease was primarily the result of the fixed-asset impairments in the fourth quarter of 2016 and the first quarter of 2017, which reduced depreciation expense due to lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

During the nine months ended September 30, 2017, Depreciation and amortization decreased $18.5 million, compared to the same period in the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016, and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

DPL – General Taxes
During the three months ended September 30, 2017, General taxes decreased $1.5 million compared to the same period in the prior year. The decrease was primarily the result of a true-up of the year to date 2017 Ohio property tax accrual to reflect final assessments for 2017 taxes.

During the nine months ended September 30, 2017, General taxes increased $4.1 million compared to the same period in the prior year. The increase was primarily the result of lower Ohio property tax expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016 and a 2017 unfavorable true-up of $1.2 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017, as well as higher Ohio property tax rates in 2017.

DPL – Fixed-asset Impairment
During the nine months ended September 30, 2017, DPL recorded an impairment of fixed-assets of $66.4 million. DPL recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

During the nine months ended September 30, 2016, DPL recorded an impairment of fixed assets of $235.5 million. For more information, see Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

DPL – Loss (Gain) on Asset Disposal
During the nine months ended September 30, 2017, DPL recorded a loss on asset disposal of $15.9 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.


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DPL – Other
During the three and nine months ended September 30, 2017, Other operating expenses were reduced by $4.5 million and $5.4 million, respectively, primarily due to insurance recoveries recorded in 2017.

DPL – Charge for Early Redemption of Debt
During the three and nine months ended September 30, 2017, DPL recorded a charge for early redemption of debt of $3.0 million and $3.3 million, respectively, primarily due to the early redemption of the 4.8% Tax-exempt First Mortgage Bonds due 2036.

During the three and nine months ended September 30, 2016, DPL recorded a charge for early redemption of debt of $0.5 million and $3.1 million, respectively. The $3.1 million charge was primarily due to the February 2016 make-whole premium of $2.4 million associated with the early redemption of $73.0 million of the 6.5% Senior Notes due in 2016.

DPL – Income Tax Expense
During the three months ended September 30, 2017, Income tax expense decreased $6.6 million compared to the same period in the prior year primarily due to a year-to-date adjustment for the decrease in the annualized effective rate.

During the nine months ended September 30, 2017, Income tax benefit decreased $57.9 million compared to the same period in the prior year primarily due to a significantly larger pre-tax loss in the prior year versus the current year.

RESULTS OF OPERATIONS BY SEGMENT – DPL Inc.

DPL currently manages the business through two reportable operating segments, the 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 this measure 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 520,000 retail customers 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 recording 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 did not transfer to AES Ohio Generation on October 1, 2017 when DP&L’s generation separation occurred, 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. Through September 30, 2017, AES Ohio Generation owned and operated peaking generating facilities, and DP&L owned multiple coal-fired and peaking electric generating facilities. As a result of Generation Separation, the DP&L-owned generating facilities were transferred to AES Ohio Generation on October 1, 2017.

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 long-term 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.


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Intersegment sales and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.

See Note 11 – Business Segments of Notes to DPL’s Condensed 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:
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
T&D $20.0
 $36.4
 $60.1
 $97.9
Generation 29.9
 14.2
 (43.7) (857.2)
Other (21.9) (22.8) (62.8) 564.8
Income / (loss) from continuing operations before income tax (a) $28.0
 $27.8
 $(46.4) $(194.5)

(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.



79

Statement of Operations Highlights – DPL Inc. – T&D Segment
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues:        
Retail $164.0
 $197.6
 $487.8
 $553.9
Wholesale 5.9
 5.3
 14.5
 12.3
RTO revenues 12.5
 11.5
 35.5
 34.2
RTO capacity revenues 1.8
 1.4
 4.7
 5.0
Total revenues 184.2
 215.8
 542.5
 605.4
Cost of revenues:        
Net fuel cost —
 —
 —
 5.3
Purchased power:        
Purchased power 58.2
 73.9
 178.2
 199.9
RTO charges 15.7
 15.7
 43.2
 44.3
RTO capacity charges 0.5
 0.2
 0.6
 (0.2)
Net purchased power cost 74.4
 89.8
 222.0
 244.0
Total cost of revenues 74.4
 89.8
 222.0
 249.3
         
Gross margin 109.8
 126.0
 320.5
 356.1
         
Operating expenses:        
Operation and maintenance 42.4
 47.3
 121.4
 134.9
Depreciation and amortization 19.6
 17.8
 56.3
 55.1
General taxes 19.3
 17.7
 57.8
 50.7
Gain on asset disposal (0.3) —
 (0.3) (0.4)
Total operating expenses 81.0
 82.8
 235.2
 240.3
         
Operating income 28.8
 43.2
 85.3
 115.8
         
Other expense, net        
Investment income 0.1
 0.1
 0.2
 0.3
Interest expense (7.7) (6.5) (22.9) (17.5)
Charge for early redemption of debt (1.0) (0.5) (1.1) (0.5)
Other expense (0.2) 0.1
 (1.4) (0.2)
Total other expense, net (8.8) (6.8) (25.2) (17.9)
         
Income from continuing operations before income tax (a) $20.0
 $36.4
 $60.1
 $97.9

(a)For purposes of discussing operating results, we present and discuss Income 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 Inc. –T&D Segment – Revenues
During the three months ended September 30, 2017, the segment’s revenues decreased $31.6 million to $184.2 million from $215.8 million in the same period of the prior year. This decrease was primarily the result of lower retail volumes and lower average retail rates.
Retail revenues decreased $33.6 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, lower rates associated with the competitive bid rider, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs


80

recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as cooling degree days decreased by 290 degree days. The aforementioned impacts resulted in an unfavorable $15.5 million retail volume variance and an unfavorable $17.0 million retail price variance. In addition, there was an unfavorable other miscellaneous variance of $1.1 million.
Wholesale revenues increased $0.6 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 $1.4 million compared to the same period in the prior year.

During the nine months ended September 30, 2017, the segment’s revenues decreased $62.9 million to $542.5 million from $605.4 million in the same period of the prior year. This decrease was primarily the result of lower retail volumes and lower average retail rates.
Retail revenues decreased $66.1 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 449 degree days and cooling degree days decreased by 313 degree days. The aforementioned impacts resulted in an unfavorable $35.2 million retail price variance and an unfavorable $34.1 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $3.2 million.
Wholesale revenues increased $2.2 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. As such, the increase in wholesale revenue is due to increased OVEC revenue.
RTO capacity and other revenues increased $1.0 million compared to the same period in the prior year.

DPL Inc. –T&D Segment – Cost of Revenues
During the three months ended September 30, 2017, Total cost of revenues decreased $15.4 million compared to the prior year. This decrease was a result of:
Net purchased power decreased $15.4 million compared to the prior year. This was driven by the following factors:
◦
Purchased power decreased $15.7 million compared to the same period in the prior year primarily due to a favorable price variance of $7.4 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $8.3 million due to the decrease in DP&L retail demand in 2017.
◦RTO capacity and other charges increased $0.3 million compared to the same period in the prior year.

During the nine months ended September 30, 2017, Total cost of revenues decreased $27.3 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, decreased $5.3 million compared to the prior year primarily due to fuel costs deferred in 2015, being collected in 2016. There were no fuel costs deferred or collected in 2017.
Net purchased power decreased $22.0 million compared to the prior year. This was driven by the following factors:
◦
Purchased power decreased $21.7 million compared to the same period in the prior year primarily due to a favorable price variance of $8.5 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $13.2 million due to the decrease in DP&L retail demand in 2017.
◦RTO capacity and other charges decreased $0.3 million compared to the same period in the prior year.



81

DPL Inc. –T&D Segment – Operating Expenses
During the three and six months ended June 30, 2017, Operating expenses decreased $1.8 million and $5.1 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 vs. 2016 2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
 $(6.3) $(18.4)
Increase in General taxes (b)
 1.6
 7.1
Increase / (decrease) in group insurance expense associated with participation in the AES self-insurance plan (0.1) 3.4
Increase in legal and other consulting costs 0.5
 2.5
Increase in Depreciation and amortization expense primarily due to additional investments in T&D fixed assets 1.8
 1.2
Other, net 0.7
 (0.9)
Net change in operating expenses $(1.8) $(5.1)

(a)There is a corresponding offset in Revenues associated with these programs, resulting in no impact to Income from continuing operations before income tax.

(b)During the three months ended September 30, 2017, General taxes increased $1.6 million compared to the same period in the prior year. The increase was primarily the result of higher Ohio property tax expense driven by higher tax rates and property values. During the nine months ended September 30, 2017, General taxes increased $7.1 million compared to the same period in the prior year. The increase was primarily the result of higher Ohio property tax expense driven by higher tax rates, higher property values, lower expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016, and a 2017 unfavorable true-up of $1.2 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017.

DPL Inc. –T&D Segment – Interest Expense
During the three months ended September 30, 2017, Interest expense increased $1.2 million compared to the same period in the prior year primarily driven by higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

During the nine months ended September 30, 2017, Interest expense increased $5.4 million compared to the same period in the prior year primarily driven by higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.



82

Statement of Operations Highlights–DPL Inc. – Generation Segment
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues:        
Retail $0.1
 $0.1
 $0.2
 $0.2
Wholesale 96.3
 133.6
 286.1
 357.3
RTO revenues 2.8
 5.3
 8.2
 13.0
RTO capacity revenues 38.0
 31.5
 101.9
 99.6
Other mark-to-market losses —
 (0.1) —
 (0.1)
Total revenues 137.2
 170.4
 396.4
 470.0
Cost of revenues:        
Fuel cost:        
Fuel 57.6
 80.4
 166.3
 205.3
Losses from the sale of coal (0.3) (1.9) (0.9) (4.6)
Mark-to-market losses —
 0.4
 —
 —
Net fuel cost 57.3
 78.9
 165.4
 200.7
Purchased power:        
Purchased power 4.6
 11.2
 21.8
 54.6
RTO charges 0.1
 7.5
 10.1
 15.9
RTO capacity charges 3.3
 3.4
 10.1
 18.7
Mark-to-market losses / (gains) 1.2
 (1.2) (1.0) (2.7)
Net purchased power cost 9.2
 20.9
 41.0
 86.5
Total cost of revenues 66.5
 99.8
 206.4
 287.2
         
Gross margin 70.7
 70.6
 190.0
 182.8
         
Operating expenses:        
Operation and maintenance 40.3
 45.5
 130.0
 124.8
Depreciation and amortization 4.7
 7.7
 16.6
 44.6
General taxes 0.9
 3.8
 10.4
 13.4
Fixed-asset impairment —
 —
 66.3
 857.1
Loss / (gain) on asset disposal —
 (0.7) 16.2
 (0.2)
Other (5.2) —
 (6.1) —
Total operating expenses 40.7
 56.3
 233.4
 1,039.7
         
Operating income / (loss) 30.0
 14.3
 (43.4) (856.9)
         
Other expense, net        
Interest expense —
 (0.1) (0.2) (0.3)
Other expense (0.1) —
 (0.1) —
Total other expense, net (0.1) (0.1) (0.3) (0.3)
         
Income / (loss) from continuing operations before income tax (a) $29.9
 $14.2
 $(43.7) $(857.2)

(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.



83

DPL Inc. –Generation Segment – Revenues
During the three months ended September 30, 2017, the segment’s revenues decreased $33.2 million to $137.2 million from $170.4 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and lower average wholesale rates, partially offset by higher RTO capacity and other revenues.
Wholesale revenues decreased $37.3 million primarily as a result of an unfavorable wholesale volume variance of $33.2 million and an unfavorable wholesale price variance of $4.1 million. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 20% decrease in internal generation at DPL's plants in 2017.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, increased $4.0 million compared to the same period in the prior year. This increase was the result of a $6.5 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $2.5 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.

During the nine months ended September 30, 2017, the segment’s revenues decreased $73.6 million to $396.4 million from $470.0 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes, lower average wholesale rates, and lower RTO capacity and other revenues.
Wholesale revenues decreased $71.2 million primarily as a result of an unfavorable wholesale volume variance of $48.7 million and an unfavorable wholesale price variance of $22.5 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process and a 10% decrease in internal generation at DPL's plants in 2017.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $2.5 million compared to the same period in the prior year primarily due to a $4.8 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves. This decrease was partially offset by a $2.3 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DPL Inc. –Generation Segment – Cost of Revenues
During the three months ended September 30, 2017, Total cost of revenues decreased $33.3 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 $21.6 million compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 20% decrease in internal generation.
Net purchased power decreased $11.7 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $6.6 million primarily due to a favorable volume variance of $3.5 million and a favorable price variance of $3.1 million. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016. The price decrease was primarily driven by lower PJM market rates in the third quarter of 2017. The generation segment purchases power to source retail load in other service territories and 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.


84

◦RTO charges decreased $7.4 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.
◦RTO capacity charges decreased $0.1 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, partially offset by higher RTO capacity prices. Retail load served relates to the load of other parties through their competitive bid process.
◦Mark-to-market losses increased $2.4 million due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Total cost of revenues decreased $80.8 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 $35.3 million compared to the same period in the prior year primarily due to a 13% decrease in average fuel cost per MWh and a 10% decrease in internal generation.
Net purchased power decreased $45.5 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $32.8 million primarily due to a favorable volume variance of $29.9 million and a favorable price variance of $2.9 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. The price decrease was primarily driven by lower PJM market rates. The generation segment purchases power to source retail load in other service territories and 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 $5.8 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.
◦RTO capacity charges decreased $8.6 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.
◦Mark-to-market gains decreased $1.7 million due to changes in power prices in 2017 and 2016.



85

DPL Inc. –Generation Segment ��� Operating Expenses
During the three and six months ended June 30, 2017, Operating expenses decreased $15.6 million and $806.3 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 vs. 2016 2017 vs. 2016
Change in Fixed-asset impairment from 2016 to 2017 (a)
 $—
 $(790.8)
Decrease in Depreciation and amortization expense as a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values (3.0) (28.0)
Higher insurance recoveries in 2017 (5.2) (6.1)
Decrease in General taxes due to a true-up of the year to date 2017 Ohio property tax accrual for generation to reflect final assessments for 2017 taxes recorded in the third quarter of 2017 (2.9) (3.0)
Decrease in generating facilities operating and maintenance expenses (5.6) (2.4)
Loss on asset disposal (b)
 0.7
 16.4
Increase / (decrease) in retirement benefit costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter

 (0.1) 5.6
Increase in group insurance expenses associated with participation in the AES self-insurance plan 0.1
 3.9
Other, net 0.4
 (1.9)
Net change in operating expenses $(15.6) $(806.3)

(a)
During the nine months ended September 30, 2017, the Generation segment recorded a fixed-asset impairment of $66.3 million. The Generation segment recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station, respectively. During the nine months ended September 30, 2016, the Generation segment recorded a fixed-asset impairment of $857.1 million. The Generation segment recognized asset impairment expense of $230.8 million and $4.7 million for Killen Station and certain DP&L peaking generating facilities, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements.

(b)During the nine months ended September 30, 2017, the Generation segment recorded a loss on asset disposal of $15.9 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

DPL Inc. –Generation Segment – Interest Expense
During the three and nine months ended September 30, 2017, Interest expense did not change significantly compared to the same periods in the prior year.

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. The order also stated if DP&L cannot rebalance its capital structure by January 1, 2018, it should file an application explaining why it was unable to do so and the steps that it was taking to get back to a 50/50 capital structure. DP&L has complied with the PUCO's order by filing such an application. For historical segment purposes, up to $750.0 million of long-term 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.



86

RESULTS OF OPERATIONS HIGHLIGHTS – DP&L
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues:        
Retail $164.1
 $197.7
 $488.0
 $554.1
Wholesale 95.0
 127.9
 283.9
 347.2
RTO revenues 14.5
 15.2
 41.0
 43.9
RTO capacity revenues 32.0
 27.6
 87.9
 86.2
Other mark-to-market losses —
 —
 —
 (0.1)
Total revenues 305.6
 368.4
 900.8
 1,031.3
Cost of revenues:        
Fuel cost:        
Fuel 53.1
 72.5
 153.7
 194.4
Gains from the sale of coal (0.3) (1.9) (0.9) (4.9)
Mark-to-market losses —
 0.4
 —
 —
Net fuel cost 52.8
 71.0
 152.8
 189.5
Purchased power:        
Purchased power 62.9
 85.3
 199.3
 254.2
RTO charges 16.0
 22.7
 52.9
 59.1
RTO capacity charges 3.4
 3.3
 9.5
 17.4
Mark-to-market losses / (gains) 1.2
 (1.3) (1.0) (2.7)
Net purchased power cost 83.5
 110.0
 260.7
 328.0
Total cost of revenues 136.3
 181.0
 413.5
 517.5
         
Gross margin 169.3
 187.4
 487.3
 513.8
         
Operating expenses:        
Operation and maintenance 81.7
 85.5
 245.2
 248.0
Depreciation and amortization 22.7
 24.1
 68.2
 95.2
General taxes 19.6
 21.2
 66.8
 62.8
Gain on termination of contract —
 —
 —
 (27.7)
Fixed-asset impairment —
 —
 66.3
 857.1
Loss / (gain) on asset disposal (0.3) —
 15.9
 0.2
Other (4.4) —
 (4.4) —
Total operating expenses 119.3
 130.8
 458.0
 1,235.6
         
Operating income / (loss) 50.0
 56.6
 29.3
 (721.8)
         
Other expense, net        
Investment income 0.1
 0.1
 0.2
 0.3
Interest expense (7.7) (6.5) (23.1) (17.2)
Charge for early redemption of debt (1.0) (0.5) (1.1) (0.5)
Other expense (0.2) 0.1
 (1.5) (0.2)
Total other expense, net (8.8) (6.8) (25.5) (17.6)
         
Income / (loss) from operations before income tax (a) $41.2
 $49.8
 $3.8
 $(739.4)

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



87

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

We sell generation into the wholesale market which covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; retail demand throughout the entire wholesale market area; availability of our generating plants and non-affiliated generating plants to sell into the wholesale market; contracted wholesale sales and our variable generation costs. Our goal is to make wholesale sales when it is profitable to do so.

The following table provides a summary of changes in revenues compared to the same period in the prior year:

 Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 vs. 2016 2017 vs. 2016
Retail    
Rate $(17.0) $(35.3)
Volume (15.5) (34.2)
Other miscellaneous (1.1) 3.4
Total retail change (33.6) (66.1)
  
 
Wholesale    
Rate (9.4) (27.4)
Volume (23.5) (35.9)
Total wholesale change (32.9) (63.3)
  
 
RTO revenues and RTO capacity revenues    
RTO revenues and RTO capacity revenues 3.7
 (1.2)
     
Other    
Unrealized MTM —
 0.1
  
 
Total revenues change $(62.8) $(130.5)

During the three months ended September 30, 2017, Revenues decreased $62.8 million to $305.6 million from $368.4 million in the same period in the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $33.6 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, lower rates associated with the competitive bid rider, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as cooling degree days decreased by 290 degree days. The aforementioned impacts resulted in an unfavorable $17.0 million retail price variance and an unfavorable $15.5 million retail volume variance. In addition, there was an unfavorable other miscellaneous variance of $1.1 million.

Wholesale revenues decreased $32.9 million primarily as a result of an unfavorable $23.5 million wholesale volume variance and an unfavorable $9.4 million wholesale price variance. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes of $23.5 million was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 19% decrease in internal generation at DP&L's plants in 2017.


88


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 $3.7 million compared to the same period in the prior year. This increase was the result of a $4.4 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $0.7 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.

During the nine months ended September 30, 2017, Revenues decreased $130.5 million to $900.8 million from $1,031.3 million in the same period in the prior year. This decrease was primarily the result of the components of revenue discussed below:

Retail revenues decreased $66.1 million primarily due to lower average DP&L retail rates and lower DP&L retail volumes. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016, collections on the remaining 2015 deferred fuel balance in the first quarter of 2016, and a decrease in the USF revenue rate rider, partially offset by increased revenue associated with energy efficiency programs recorded in 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree days decreased by 449 degree days and cooling degree days decreased by 313 degree days. The aforementioned impacts resulted in an unfavorable $35.3 million retail price variance and an unfavorable $34.2 million retail volume variance. These variances were partially offset by a favorable other miscellaneous variance of $3.4 million.

Wholesale revenues decreased $63.3 million primarily as a result of an unfavorable $35.9 million wholesale volume variance and an unfavorable $27.4 million wholesale price variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $35.9 million was primarily driven by a decrease in the load served of other parties through their competitive bid process and an 8% decrease in internal generation at DP&L's plants in 2017.

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 $1.2 million compared to the same period in the prior year. This decrease was the result of a $2.9 million decrease in RTO revenues due to lower rates and availability related to compensation for DP&L's reactive supply and operating reserves. This decrease was partially offset by a $1.7 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DP&L – Cost of Revenues
During the three months ended September 30, 2017, Cost of revenues decreased $44.7 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $18.2 million, compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 19% decrease in internal generation at DP&L's plants in 2017.

Net purchased power decreased $26.5 million compared to the prior year. This decrease was driven by the following factors:

◦
Purchased power decreased $22.4 million primarily due to a $12.2 million volume decrease and a $10.2 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016 and lower PJM market rates.



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◦
RTO charges decreased $6.7 million compared to the same period in the prior year due to lower transmission and congestion charges. 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 transmission 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 $0.1 million compared to the same period in the prior year primarily due to increases in RTO capacity prices. As noted above, RTO capacity prices are set by an annual auction. The increase in RTO capacity prices was partially offset by a lower retail load served in 2017. Retail load served relates to the load of other parties through their competitive bid process.

◦Mark-to-market losses increased $2.5 million compared to the same period in the prior year due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Cost of revenues decreased $104.0 million compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $36.7 million, compared to the same period in the prior year primarily due to a 14% decrease in average fuel cost per MWh and an 8% decrease in internal generation. There were fuel costs deferred in 2015, which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. There were no fuel costs deferred or collected in 2017.

Net purchased power decreased $67.3 million compared to the prior year. This decrease was driven by the following factors:

◦
Purchased power decreased $54.9 million primarily due to a $35.0 million volume decrease and a $19.9 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 than 2016.

◦
RTO charges decreased $6.2 million compared to the same period in the prior year due to lower transmission and congestion charges. 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 transmission 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 $7.9 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.

◦Mark-to-market gains decreased $1.7 million compared to the same period in the prior year due to changes in power prices in 2017 and 2016.



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DP&L – Operation and Maintenance
During the three and nine months ended September 30, 2017, Operation and Maintenance expense decreased $3.8 million and $2.8 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 vs. 2016 2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
 $(6.3) $(18.4)
Decrease in generating facilities operating and maintenance expenses (3.6) (2.3)
Increase in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter of 2017
 0.7
 7.6
Increase in group insurance expense associated with participation in the AES self-insurance plan
 —
 7.2
Insurance recoveries from MVIC in 2016 2.9
 2.9
Increase in legal and other consulting costs 1.2
 2.8
Other, net 1.3
 (2.6)
Net change in operation and maintenance expense $(3.8) $(2.8)

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

DP&L – Depreciation and Amortization
During the three months ended September 30, 2017, Depreciation and amortization decreased $1.4 million, compared to the same period in the prior year. The decrease was primarily the result of the fixed-asset impairments in the fourth quarter of 2016 and the first quarter of 2017, which reduced depreciation expense due to lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

During the nine months ended September 30, 2017, Depreciation and amortization decreased $27.0 million, compared to the same period in the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the pending sale of these two plants.

DP&L – General Taxes
During the three months ended September 30, 2017, General taxes decreased $1.6 million compared to the same period in the prior year. The decrease was primarily the result of a true-up of the 2017 Ohio property tax accrual to reflect final assessments for 2017 taxes.

During the nine months ended September 30, 2017, General taxes increased $4.0 million compared to the same period in the prior year. The increase was primarily the result of lower Ohio property tax expense in 2016 due to a $1.6 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016 and a 2017 unfavorable true-up of $1.2 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017, as well as higher Ohio property tax rates in 2017.

DP&L – Gain on Termination of Contract
During the nine months ended September 30, 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 – Fixed-asset Impairment
During the nine months ended September 30, 2017, DP&L recorded an impairment of fixed-assets of $66.3 million. DP&L recognized asset impairment expense of $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

During the nine months ended September 30, 2016, DP&L recorded an impairment of fixed assets of $857.1 million. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue


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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. 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. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

DP&L – Loss / (gain) on asset disposal
During the nine months ended September 30, 2017, DP&L recorded a loss on asset disposal of $15.9 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

DP&L – Other
During the three and nine months ended September 30, 2017, Other operating expenses were reduced by $4.4 million primarily due to insurance recoveries recorded in 2017.

DP&L – Interest Expense
During the three months ended September 30, 2017, Interest expense increased $1.2 million compared to the same period in the prior year primarily due to higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

During the nine months ended September 30, 2017, Interest expense increased $5.9 million compared to the same period in the prior year primarily due to higher interest rates on the $445.0 million variable rate Term Loan B maturing on August 24, 2022 compared to the interest rate on the 1.875% First Mortgage Bonds Due 2016.

DP&L – Income Tax Expense
During the three months ended September 30, 2017, Income tax expense decreased $7.8 million compared to the same period in the prior year primarily due to a lower annualized effective tax rate and lower pretax income in the current year versus the prior year.

During the nine months ended September 30, 2017, Income tax expense / (benefit) decreased $271.8 million compared to the same period in the prior year primarily due to a significantly large pre-tax loss in the prior year versus pre-tax income in the current year.

RESULTS OF OPERATIONS BY SEGMENT – DP&L

Through September 30, 2017, DP&L managed the business through two reportable operating segments, the T&D segment and the Generation segment. After Generation Separation, DP&L will have only one reportable operating segment, the T&D segment, beginning on October 1, 2017. The primary segment performance measure is income / (loss) from operations before income tax as management has concluded that this measure 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-Q. 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
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 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.

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, costs of sales and expenses are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.



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See Note 12 – Business Segments of Notes to DP&L’s Condensed 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:
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
T&D $20.0
 $36.5
 $60.1
 $98.5
Generation 21.2
 13.3
 (56.3) (837.9)
Income / (loss) from operations before income tax (a) $41.2
 $49.8
 $3.8
 $(739.4)

(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.



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Statement of Operations Highlights – DP&L – Generation Segment
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 2016 2017 2016
Revenues:        
Retail $0.1
 $0.1
 $0.2
 $0.2
Wholesale 89.1
 122.6
 269.4
 334.9
RTO revenues 2.0
 3.7
 5.5
 9.7
RTO capacity revenues 30.2
 26.2
 83.2
 81.2
Other mark-to-market losses —
 —
 —
 (0.1)
Total revenues 121.4
 152.6
 358.3
 425.9
Cost of revenues:        
Cost of fuel:        
Fuel 53.1
 72.5
 153.7
 188.8
Gains from the sale of coal (0.3) (1.9) (0.9) (4.6)
Mark-to-market losses —
 0.4
 —
 —
Net fuel cost 52.8
 71.0
 152.8
 184.2
Purchased power:        
Purchased power 4.7
 11.4
 21.1
 54.3
RTO charges 0.3
 7.0
 9.7
 14.8
RTO capacity charges 2.9
 3.1
 8.9
 17.6
Mark-to-market losses / (gains) 1.2
 (1.3) (1.0) (2.7)
Net purchased power cost 9.1
 20.2
 38.7
 84.0
Total cost of revenues 61.9
 91.2
 191.5
 268.2
         
Gross margin 59.5
 61.4
 166.8
 157.7
         
Operating expenses:        
Operation and maintenance 39.3
 38.2
 123.8
 113.1
Depreciation and amortization 3.1
 6.3
 11.9
 40.1
General taxes 0.3
 3.5
 9.0
 12.1
Gain on termination of contract —
 —
 —
 (27.7)
Fixed-asset impairment —
 —
 66.3
 857.1
Loss on asset disposal —
 —
 16.2
 0.6
Other (4.4) —
 (4.4) —
Total operating expenses 38.3
 48.0
 222.8
 995.3
         
Other income / (expense), net 21.2
 13.4
 (56.0) (837.6)
         
Other expense, net        
Interest expense —
 (0.1) (0.2) (0.3)
Other expense —
 —
 (0.1) —
Total other expense, net —
 (0.1) (0.3) (0.3)
         
Income / (loss) from operations before income tax (a) $21.2
 $13.3
 $(56.3) $(837.9)

(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.



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DP&L –Generation Segment – Revenues
During the three months ended September 30, 2017, the segment’s revenues decreased $31.2 million to $121.4 million from $152.6 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes and lower average wholesale rates, partially offset by higher RTO capacity and other revenues.
Wholesale revenues decreased $33.5 million primarily as a result of an unfavorable wholesale volume variance of $29.2 million and an unfavorable wholesale price variance of $4.3 million. The unfavorable price variance was due to lower PJM market prices in the third quarter of 2017 and lower realized gains on derivatives. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process, as well as a 19% decrease in internal generation at DP&L's plants in 2017.
RTO capacity and other revenues increased $2.3 million compared to the same period in the prior year. This increase was the result of a $4.0 million increase in revenue realized from the PJM capacity auction in 2017 due to higher prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016. This increase was partially offset by a $1.7 million decrease in RTO revenues due to lower rates and availability related to compensation for DP&L's reactive supply and operating reserves.

During the nine months ended September 30, 2017, the segment’s revenues decreased $67.6 million to $358.3 million from $425.9 million in the same period of the prior year. This decrease was primarily the result of lower wholesale volumes, lower average wholesale rates, and lower RTO capacity and other revenues.
Wholesale revenues decreased $65.5 million primarily as a result of an unfavorable wholesale volume variance of $41.6 million and an unfavorable wholesale price variance of $23.9 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes was primarily driven by a decrease in the load served of other parties through their competitive bid process and an 8% decrease in internal generation at DP&L's plants in 2017.
RTO capacity and other revenues, consisting primarily of PJM capacity payments, decreased $2.2 million compared to the same period in the prior year primarily due to a $4.2 million decrease in RTO revenues due to lower rates and availability related to compensation for DP&L's reactive supply and operating reserves. This decrease was partially offset by a $2.0 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015.

DP&L –Generation Segment – Cost of Revenues
During the three months ended September 30, 2017, Total cost of revenues decreased $29.3 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 $18.2 million compared to the same period in the prior year primarily due to a 10% decrease in average fuel cost per MWh and a 19% decrease in internal generation at DP&L's plants in 2017.
Net purchased power decreased $11.1 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $6.7 million primarily due to a favorable volume variance of $4.5 million and a favorable price variance of $2.2 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. The price decrease was primarily driven by lower PJM market rates in the third quarter of 2017. The generation segment purchases power to source retail load in other service territories and 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 $6.7 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.


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◦RTO capacity charges decreased $0.2 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, partially offset by higher RTO capacity prices. Retail load served relates to the load of other parties through their competitive bid process.
◦Mark-to-market losses increased $2.5 million due to changes in power prices in 2017 and 2016.

During the nine months ended September 30, 2017, Total cost of revenues decreased $76.7 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 $31.4 million compared to the same period in the prior year primarily due to a 14% decrease in average fuel cost per MWh and an 8% decrease in internal generation at DP&L's plants in 2017.
Net purchased power decreased $45.3 million compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power decreased $33.2 million primarily due to a favorable volume variance of $29.9 million and a favorable price variance of $3.3 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. The generation segment purchases power to source retail load in other service territories and 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 $5.1 million compared to the same period in the prior year primarily due to lower transmission and congestion charges.
◦RTO capacity charges decreased $8.7 million compared to the same period in the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.
◦Mark-to-market gains decreased $1.7 million due to changes in power prices in 2017 and 2016.



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DP&L –Generation Segment – Operating Expenses
During the three and six months ended June 30, 2017, Operating expenses decreased $9.7 million and $772.5 million, respectively, compared to the same periods in the prior year. The main drivers of these changes are as follows:
  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2017 vs. 2016 2017 vs. 2016
Change in Fixed-asset impairment from 2016 to 2017 (a)
 $—
 $(790.8)
Decrease in Depreciation and amortization expense as a result of the fixed-asset impairments in the second and fourth quarters of 2016 and the first quarter of 2017, which reduced depreciation expense due to the lower asset values (3.2) (28.2)
Higher insurance recoveries in 2017 (4.4) (4.4)
Decrease in General taxes due to a true-up of the year to date 2017 Ohio property tax accrual for generation to reflect final assessments for 2017 taxes recorded in the third quarter of 2017 (3.2) (3.1)
Decrease in generating facilities operating and maintenance expenses (2.6) (1.0)
Gain on termination of contract in 2016 —
 27.7
Loss on asset disposal (b)
 —
 15.6
Increase / (decrease) in retirement benefits costs, primarily due to pension curtailment charges associated with announced plant closures in the first quarter (0.1) 5.7
Increase in group insurance expense associated with participation in the AES self-insurance plan —
 3.8
Other, net 3.8
 2.2
Net change in operating expenses $(9.7) $(772.5)

(a)
During the nine months ended September 30, 2017, the Generation segment recorded a fixed-asset impairment of $66.3 million. The Generation segment recognized an asset impairment expense of $39.0 million and $27.3 million for Stuart Station and Killen Station, respectively. During the nine months ended September 30, 2016, the Generation segment recorded a fixed-asset impairment of $857.1 million. The Generation segment recognized an asset impairment expense of $292.0 million, $246.2 million and $318.9 million for Stuart Station, Killen Station and Zimmer station, respectively. For more information, see Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements.

(b)During the nine months ended September 30, 2017, the Generation segment recorded a loss on asset disposal of $16.2 million primarily related to the write-off of plant materials and supplies inventory at the Stuart and Killen plants.

DP&L –Generation Segment – Interest Expense
During the three and nine months ended September 30, 2017, Interest expense did not change significantly compared to the same periods in the prior year.

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. The order also stated if DP&L cannot rebalance its capital structure by January 1, 2018, it should file an application explaining why it was unable to do so and the steps that it was taking to get back to a 50/50 capital structure. DP&L has complied with the PUCO's order by filing such an application. For historical segment purposes, up to $750.0 million of long-term 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.

KEY TRENDS AND UNCERTAINTIES

During the remainder of 2017 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, energy efficiency and wholesale prices. In addition, DPL's and DP&L's financial results are likely to be driven by many factors including, but not limited to:
PJM capacity prices;
Effect of implementing DP&L's ESP 3 order approved on October 20, 2017 with rates to be effective November 1, 2017;


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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 generation assets now owned by AES Ohio Generation; and
DPL's ability to reduce its cost structure.

Operational
On March 17, 2017, the Board of Directors of DP&L approved the retirement of the DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the DP&L operated and co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018, and the co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. In the first quarter of 2017, DPL incurred an impairment charge of $66.4 million and DP&L incurred an impairment charge of $66.3 million related to these planned retirements. See Note 14 – Fixed-asset Impairments of Notes to DPL's Condensed Consolidated Financial Statements and Note 14 – Fixed-asset Impairments of Notes to DP&L's Condensed Financial Statements for more information. DPL and DP&L also recorded pension curtailment charges of $4.1 million and $5.6 million, respectively, and inventory write off charges of $16.2 million in the first quarter of 2017 associated with the planned retirement.

In addition to the charges noted above, DPL and DP&L estimate that they will incur $7.0 million to $13.0 million in severance and benefit related costs during 2017 and 2018 and approximately $10.0 million to $30.0 million in plant shutdown costs, the timing of which is uncertain as of the date of this report. In addition, DPL also estimates future cash expenditures of approximately $130.0 million for asset retirement obligations beginning in June 2018 and through 2023.

On October 1, 2017, Stuart Unit 1 was retired due to damage sustained when a high-pressure feedwater heater shell failed on January 10, 2017.

In addition to our plans to exit coal capacity, we are pursuing the sale of our peaker generation assets. We expect to announce a transaction by year-end with closing expected in the first half of 2018.

For additional information on DP&L's coal fired facilities see Note 4 – Property, Plant and Equipment of Notes to DPL's Condensed Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L's Condensed Financial Statements.

Regulatory Environment
For a comprehensive discussion of the market structure and regulation of DPL and DP&L, see Part I, Item 2 - OHIO COMPETITION AND REGULATORY PROCEEDINGS.

In January 2017, DP&L filed a settlement in its ESP 3 case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The ESP establishes DP&L's framework for providing retail service on a going forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory 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:

Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;
The establishment of a three-year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 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. With PUCO approval, DP&L has the option of extending the duration of the DMR for an additional two years;
The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which is to be established in a separate DP&L distribution rate case
A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs;
Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and


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competitive retail market enhancements, with tariffs consistent with the order to be effective November 1, 2017;
A commitment to commence a sale process to sell our ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L; and
Restrictions on DPL making dividend or tax sharing payments; and
Various other riders and competitive retail market enhancements.

On April 21, 2017, DP&L and AES Ohio Generation entered into an agreement for the sale of DP&L’s undivided interests in Zimmer and Miami Fort for $50.0 million in cash and the assumption of certain liabilities, including environmental liabilities. The purchase price is subject to adjustment at closing based on the amount of certain inventories, pre-paid amounts, employment benefits, insurance premiums, property taxes and other costs. The sale is subject to approval by the FERC and is expected to close in the fourth quarter of 2017.

In connection with any sale or closure of our generation plants as contemplated by the ESP 3 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.

DP&L’s ESP 2 had been approved by the PUCO for the years 2014 - 2016, and permitted DP&L to collect a non-bypassable service stability rider equal to $110.0 million per year for each of those years and required DP&L to conduct competitive bid auctions to procure generation supply for SSO service. The Ohio Supreme Court in a June 2016 opinion 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 2 and implement rates consistent with those in effect prior to 2014. The PUCO approved DP&L’s withdrawal of ESP 2 and implementation plans. Those rates were in effect until rates approved as a result of DP&L’s pending ESP 3 are effective, November 1, 2017. In February 2017, several parties appealed the PUCO orders that approved both the withdrawal and the implementation plans to the Ohio Supreme Court. Those appeals are pending, and the outcome and potential financial impact of those appeals cannot be determined at this time. In July 2017, the Office of the Ohio Consumers Counsel filed a motion with the Ohio Supreme Court seeking to stay collection of the reinstated prior rates while the appeals are pending. That stay was denied by the Ohio Supreme Court in September 2017.

The Department of Energy (DOE) issued a Notice of Proposed Rule Making (NOPR) on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants are most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that are defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. The FERC is proceeding on an expedited basis, as requested by the DOE, but the timing and outcome of the proposed rule, including effects on wholesale energy markets, remains uncertain.

Environmental
We refer to the discussion in “Item 1. Business - Environmental Matters - Climate Change Legislation and Regulation”Matters” in our 20162020 Form 10-K for a discussion of certain recent developments in environmental laws and regulations, including the USEPA’s CO2 emissions rules for new electric generating units, or GHG NSPS, as well as the CO2 emissions rules for existing power plants, called the CPP. Both the GHG NSPS and the CPP are being challenged byregulations.

We have several states and industry groups in the D.C. Circuit Court. The challenges to the CPP have been fully briefed and argued but oral arguments have not yet taken place on the GHG NSPS. Challenges to both rules are currently being held in abeyance. Additionally, by orderpending environmental matters associated with our previously-owned stations. Some of the U.S. Supreme Court, the CPP has been stayed pending resolution of the challenges to the rule. On October 16, 2017, the USEPA published a proposed rule to repeal the CPP in its entirety on the legal basis that the rule exceeds the USEPA’s statutory authority. The USEPA will accept comments on the proposal until December 15, 2017.

Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form,these matters could be material. The GHG NSPS remains in effect at this time, and, absent further action from the USEPA that rescinds or substantively revises the NSPS, it could impact our plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impactadverse effect on our business,results of operations, financial condition or resultsand cash flows.

As a result of operations.



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In response to Executive Orders, USEPA is currently evaluating various existingits Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations and the retirement and subsequent sale of Conesville, the following environmental matters, regulations to be considered for repeal, replacement, or modification. We cannot predict at this time the likely outcome of the USEPA’s review of other existing regulations or what impact it may have on our business.

On September 27, 2017, the State of Maryland filed a complaint against the USEPA for failing to address its
November 2016 CAA petition to the USEPA to determine that 36 electric generating units in five upwind states, including DP&L's Killen unit, emit pollutants that contribute to non-attainment of NAAQS for Ozone in Maryland, as described further in our 2016 Form 10-K. If this petition is granted or the suit is decided favorably to the Maryland Department of the Environment, certain of our facilities could be subject to additional requirements. In light of the scheduled retirement of the Killen unit, we doand requirements are now not expect any additional requirementsexpected to have a material impact on us.DPL:

•MATS and any associated regulatory or judicial processes;
The USEPA's final CCR rule•NAAQS; and
•potential Clean Air Act Section 111(d) regulations for greenhouse gases from existing electric generating units.
Clean Air Act - Cross State Air Pollution Rule
CSAPR, which became effective onin January 2015, 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 CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the USEPA. In October 19, 2015. Generally, the rule regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR surface impoundments (ash ponds), including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. On September 13, 2017,2016, the USEPA indicatedpublished a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). The CSAPR Update Rule found that it would reconsider certain provisionsNOx ozone season emissions in 22 states (including Ohio) affect the ability of downwind states to attain and maintain the CCR2008 ozone NAAQS, and accordingly, the USEPA issued federal implementation plans that both generally provide updated CSAPR NOx ozone season emission budgets for electric generating units within these states and that implement these budgets through modifications to the CSAPR NOx ozone season allowance trading program. In December 2018, the USEPA determined that the 2016 CSAPR Update Rule fully satisfied 20 states (including Ohio) good neighbor obligations with respect to the 2008 Ozone NAAQS (“CSAPR Close-Out Rule”), obviating the need
56
for the USEPA to promulgate Federal Implementation Plans (FIPs) in these states. In October 2019, the D.C. Circuit vacated and remanded the CSAPR Close-Out Rule. On July 28, 2020, the D.C. Circuit ordered the USEPA to issue FIPs addressing seven states’ (including Ohio) outstanding 2008 NAAQS “good neighbor” obligations by March 15, 2021. On April 30, 2021, the USEPA published a final rule to address the 2020 D.C. Circuit decision. The USEPA is issuing new or amended federal implementation plans for 12 states, including Ohio, with revised CSAPR NOx ozone season emission budgets for electric generating units within these states via a new CSAPR NOx Ozone Season Group 3 Trading Program. Implementation is to begin during the 2021 ozone season (May through September 2021) with an effective date 60 days following publication in response to two petitions it received to reconsiderthe Federal Register of the final rule. ItSubject sources in these states will be required to surrender an equivalent number of previously allocated 2021-2024 Group 2 allowances by deadlines in 2021. This requirement applies inclusive of assets and allowances that have since been sold and/or retired. While DPL no longer operates electric generating units subject to the revised CSAPR Update Rule, prior AES Ohio Generation sources will be required to surrender an equivalent number of previously allocated 2021-2024 Group 2 allowances. We have accrued $0.9 million for the cost of purchasing allowances required under this rule. This accrual is too early to determine whether this may have a material impactincluded in Discontinued Operations on our business, financial condition or resultsCondensed Consolidated Statements of operations.Operations.


CAPITAL RESOURCES AND LIQUIDITY


DPL and DP&LAES Ohio had unrestricted cash and cash equivalents of $23.4$34.1 million and $15.3$16.8 million, respectively, at September 30, 2017.March 31, 2021. At that date, neither DPL nor DP&LAES Ohio had short-term investments. DPL and DP&LAES Ohio had aggregate principal amounts of long-term debt outstanding of $1,761.5$1,412.9 million and $659.6$582.3 million, respectively.


Approximately $29.7 million of DPL's long-term debt including $4.7 million of DP&L's long-term 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. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.


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 maycould have a material adverse effectseffect on our results of operations, financial condition and results of operations.cash flows. In addition, changes in the timing of tariff increases or delays in regulatory determinations could affect the cash flows and results of operations of our businesses.


Our discussion of DPL’s financial condition, liquidity and capital requirements include the results of its principal subsidiary DP&LAES Ohio. All material intercompany accounts and transactions have been eliminated in consolidation.


CASH FLOWS - DPL
DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. AES Ohio. All material intercompany accounts and transactions have been eliminated in consolidation.

Cash Flow Analysis - DPL

The following table summarizes the cash flows of DPL:
Three months ended March 31,
$ in millions20212020
Net cash provided by operating activities$5.5 $12.4 
Net cash used in investing activities(56.8)(40.2)
Net cash provided by financing activities60.0 35.0 
Net change8.7 7.2 
Balance at beginning of period25.5 47.0 
Cash, cash equivalents, and restricted cash at end of period$34.2 $54.2 

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DPL Nine months ended September 30,
$ in millions 2017 2016
Net cash provided by operating activities $81.7
 $198.6
Net cash used in investing activities (55.8) (23.1)
Net cash used in financing activities (57.1) (86.1)
     
Net change (31.2) 89.4
Balance at beginning of period 54.6
 32.4
Cash and cash equivalents at end of period $23.4
 $121.8



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DPL - Change in– Net cash flows from operating activities
Three months ended March 31,$ change
$ in millions202120202021 vs. 2020
Net income$13.6 $1.9 $11.7 
Depreciation and amortization19.1 17.8 1.3 
Deferred income taxes3.5 3.4 0.1 
Net income, adjusted for non-cash items36.2 23.1 13.1 
Net change in operating assets and liabilities(30.7)(10.7)(20.0)
Net cash provided by operating activities$5.5 $12.4 $(6.9)

The net change in operating assets and liabilities during the three months ended March 31, 2021 compared to the three months ended March 31, 2020 was driven by the following:
$ in millions$ Change
Decrease from accrued interest primarily driven by an increase in interest payments in the current year due to timing with the refinancing of debt in the second quarter of 2020$(12.7)
Decrease from accounts receivable primarily due to higher collections on generation-related receivables in the prior year(8.2)
Increase from accounts payable primarily due to timing of payments6.0 
Other(5.1)
Net decrease in cash from changes in operating assets and liabilities$(20.0)

DPL – Net cash from investing activities
Net cash used in investing activities was $(56.8) million for the three months ended March 31, 2021 compared to $(40.2) million for the three months ended March 31, 2020. This $16.6 million increase in cash used primarily relates to an $11.7 million increase in capital expenditures due to increased spending on T&D projects in the current year and $5.1 million of proceeds received from the sale of software in the prior year.

DPL – Net cash from financing activities
Net cash provided by financing activities was $60.0 million for the three months ended March 31, 2021 compared to $35.0 million from financing activities for the three months ended March 31, 2020. This $25.0 million increase is due to a $25.0 million increase in net borrowings on revolving credit facilities in the current year.

Cash Flow Analysis - AES Ohio

The following table summarizes the cash flows of AES Ohio:
Three months ended March 31,
$ in millions20212020
Net cash provided by operating activities$11.3 $— 
Net cash used in investing activities(56.2)(44.4)
Net cash provided by financing activities50.0 45.0 
Net change5.1 0.6 
Balance at beginning of period11.8 21.3 
Cash, cash equivalents, and restricted cash at end of period$16.9 $21.9 

AES Ohio – Net cash from operating activities
Three months ended March 31,$ change
$ in millions202120202021 vs. 2020
Net income$18.3 $11.7 $6.6 
Depreciation and amortization18.7 17.3 1.4 
Deferred income taxes3.2 3.0 0.2 
Net income, adjusted for non-cash items40.2 32.0 8.2 
Net change in operating assets and liabilities(28.9)(32.0)3.1 
Net cash provided by operating activities$11.3 $— $11.3 

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  Nine months ended September 30, $ change
$ in millions 2017 2016 2017 vs. 2016
Net income / (loss) $(29.3) $(89.9) $60.6
Depreciation and amortization 81.8
 100.3
 (18.5)
Impairment expenses 66.4
 235.5
 (169.1)
Gain on sale of business —
 (49.2) 49.2
Deferred income taxes (3.5) (101.4) 97.9
Other adjustments to Net income / (loss) 19.2
 3.2
 16.0
Net income / (loss), adjusted for non-cash items 134.6
 98.5
 36.1
Net change in operating assets and liabilities (52.9) 100.1
 (153.0)
Net cash provided by operating activities $81.7
 $198.6
 $(116.9)

The net change in operating assets and liabilities during the ninethree months ended September 30, 2017March 31, 2021 compared to the ninethree months ended September 30, 2016March 31, 2020 was driven by the following:
$ in millions$ Change
Increase from accounts payable primarily due to timing of payments$4.3 
Other(1.2)
Net increase in cash from changes in operating assets and liabilities$3.1 
$ in millions $ Change
Decrease from accrued taxes payable primarily due to an income tax benefit from the current year loss $(59.3)
Decrease from accounts receivable due to lower collections (7.8)
Decrease from accounts payable due to timing of payments (36.2)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities (26.0)
Decrease from inventory primarily due to lower coal purchases in 2016 (19.6)
Other (4.1)
Total decrease in cash from changes in operating assets and liabilities $(153.0)


DPL - Cash flows from investing activities
Capital expenditures, primarily related to transmission and distribution, continue to be our principal use of cash related to investing activities.AES Ohio – Net cash from investing activities
Net cash used in investing activities was $(55.8)$(56.2) million for the ninethree months ended September 30, 2017March 31, 2021 compared to $(23.1)$(44.4) million for the ninethree months ended September 30, 2016,March 31, 2020. This $11.8 million increase in cash used primarily driven by a decrease in proceeds from sale of business of $75.5 million, related to the sale of DPLER in January 2016, which was partially offset by a favorable change in restricted cash of $21.5 million, relatedrelates to a decrease$12.3 million increase in collateral requirements on derivatives, lower capital expenditures of $14.2 million, and $7.4 million higher insurance proceeds received.due to increased spending on T&D projects in the current year.


DPL - Cash flowsAES Ohio – Net cash from financing activities
Net cash used inprovided by financing activities was $(57.1)$50.0 million for thenine three months ended September 30, 2017March 31, 2021 compared to $(86.1)$45.0 million from financing activities for the ninethree months ended September 30, 2016. ForMarch 31, 2020. This $5.0 million increase relates to a $15.0 million increase in borrowings on revolving credit facilities in thenine months ended September 30, 2017, this was primarily due to $122.1 million of payments on long-term debt from the redemption of the $100.0 million 4.8% first mortgage bonds and quarterly payments on the DPL and DP&L term loans, current year, partially offset by $65.0$10.0 million net draws on revolving credit facilities. During the nine months ended September 30, 2016, we redeemed $73.0 millionin return of DPL's $130.0 million 6.5% Senior Unsecured Notes Due 2016, along with the related make-whole premium payment of $2.4 million and deferred financing costcapital payments of $8.0 million.



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CASH FLOWS - DP&L
The following table summarizes the cash flows of DP&L:
DP&L Nine months ended September 30,
$ in millions 2017 2016
Net cash provided by operating activities $98.7
 $220.4
Net cash used in investing activities (42.7) (86.6)
Net cash used in financing activities (42.3) (46.3)
     
Net change 13.7
 87.5
Balance at beginning of period 1.6
 5.4
Cash and cash equivalents at end of period $15.3
 $92.9

DP&L - Change in cash flows from operating activities
  Nine months ended September 30, $ change
$ in millions 2017 2016 2017 vs. 2016
Net income / (loss) $3.6
 $(467.8) $471.4
Depreciation and amortization 68.2
 95.2
 (27.0)
Impairment expenses 66.3
 857.1
 (790.8)
Deferred income taxes 1.6
 (314.2) 315.8
Other adjustments to Net income / (loss) 17.0
 0.7
 16.3
Net income / (loss), adjusted for non-cash items 156.7
 171.0
 (14.3)
Net change in operating assets and liabilities (58.0) 49.4
 (107.4)
Net cash provided by operating activities $98.7
 $220.4
 $(121.7)

The net change in operating assets and liabilities during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 was driven by the following:
$ in millions $ Change
Decrease from accrued taxes payable, due to income tax benefit incurred on current year loss $(40.7)
Decrease from accounts payable due to timing of payments (44.9)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities (26.0)
Decrease from inventory primarily due to lower coal purchases in 2016 (19.4)
Increase from accounts receivable due to higher collections

 31.5
Other (7.9)
Total decrease in cash from changes in operating assets and liabilities $(107.4)

DP&L - Cash flows from investing activities
Net cash from investing activities was $(42.7) million for thenine months ended September 30, 2017 compared to $(86.6) million for the nine months ended September 30, 2016, primarily due to a $21.5 million favorable change in restricted cash, due to a changeDPL in the collateral requirements on derivatives, and lower capital expenditures of $15.9 million.current year.

DP&L - Cash flows from financing activities
Net cash used in financing activities was $(42.3) million for the nine months ended September 30, 2017 compared to $(46.3) million from financing activities for the nine months ended September 30, 2016. For the nine months ended September 30, 2017, this was due to the redemption of the $100.0 million 4.8% first mortgage bonds and repayments on the DP&L term loan and dividends and returns of capital paid to parent of $19.0 million, partially offset by a $70.0 million capital contribution from DPL. During the nine months ended September 30, 2016, DP&L had net repayments of $35.0 million of short-term debt to its parent, DPL, and $8.0 million payments of deferred financing costs.



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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 hedgestaxes and dividend payments. In 2017For 2021 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations, and funds from debt financing and/or equity capital contributions as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to us to manage working capital requirements during thesethose periods.


At September 30, 2017, DP&LMarch 31, 2021, AES Ohio and DPL have access to the following revolving credit facilities:
$ in millionsTypeMaturityCommitmentAmounts available as of March 31, 2021
AES OhioRevolvingJune 2024$175.0 $93.9 
DPLRevolvingJune 2023110.0 30.0 
$285.0 $123.9 
$ in millions Type Maturity Commitment Amounts available as of September 30, 2017
DP&L Revolving July 2020 $175.0
 $158.6
DPL Revolving July 2020 205.0
 142.1
      $380.0
 $300.7


DP&LAES Ohio has an unsecured revolving credit agreement with a syndicated bank group with a borrowing limit of $175.0 million and a $50.0$75.0 million letter of credit sublimit, as well as a feature that provides DP&LAES Ohio the ability to increase the size of the facility by an additional $100.0 million. This facility expires in July 2020.June 2024. At September 30, 2017,March 31, 2021, there were two letterswas one letter of credit in the aggregate amount of $1.4$1.1 million outstanding under this facility, and $15.0$80.0 million borrowed on the facility,in borrowings, with the remaining $158.6$93.9 million available to DP&L. Fees associated with this letter of credit facility were not material during the nine months ended September 30, 2017 or 2016.AES Ohio.


DPL has a revolving credit facility of $205.0$110.0 million, with a $200.0$75.0 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$50.0 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 assets of AES Ohio Generation. DPL further secured the credit facility through a leasehold mortgage on additional assets of AES Ohio Generation.. The facility expires in July 2020; however, DPL's credit facility 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 JulyJune 2023. At March 31, 2020, then the maturity of this facility shall be July 1, 2019. At September 30, 2017,2021, there were five lettersno letter of creditcredits outstanding and $80.0 million in the aggregate amount of $12.9 million outstanding under this facility, and $50.0 million borrowed on the facility,borrowings, with the remaining $142.1$30.0 million available to DPL. Fees associated with this facility were not material during the nine months ended September 30, 2017 or 2016.DPL.

Capital Requirements
Planned construction additions for 20172021 relate primarily to new investments in and upgrades to DP&L’s power plant equipment andAES Ohio’s transmission and distribution system. Capital projects are subject to continuing review and are revised in light ofconsidering changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental requirements, among other factors.


DPL is projecting to spend an estimated $358.0$746.0 million in capital projects for the period 20172021 through 2019,2023, of which $297.0$736.0 million is projected to be spent by DP&LAES Ohio.DP&L AES Ohio's projection includes expected spending under itsSmart Grid Plan included in the Stipulation and Recommendation entered into on October 23, 2020 as well as new transmission projects. See additional information in Note 3 – Regulatory Matters of Notes to DPL's Condensed
59
Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to AES Ohio's Condensed Financial Statements.

AES Ohio is subject to the mandatory reliability standards of NERC and Reliability FirstReliabilityFirst Corporation, (RFC), one of the eightsix NERC regions, of which DP&LAES Ohio is a member. DP&LAES Ohio anticipates spending approximately $11.3$76.0 million within the next five years to reinforce its 138 kVtransmission system to comply with mandatory NERC standards. Our ability to completeand FERC Form 715 planning requirements. These anticipated costs are included in the overall 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.projections above.


Long-term debt covenants
The DPL revolving credit facilityFor information regarding our long-term debt covenants, see Part I, Item 1, Note 6 – Long-term Debt of Notes to DPL's Condensed Consolidated Financial Statements and the DPL term loan agreement have a TotalPart I, Item 1, Note 6 – Long-term Debt of Notes to EBITDA covenant 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 not to exceed 6.25AES Ohio's Condensed Financial Statements.


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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 September 30, 2017, the financial covenant was met with a ratio of 6.76 to 1.00.

The DPL revolving credit facility and the DPL term loan agreement also have an EBITDA to Interest Expense covenant 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 September 30, 2017, this financial covenant was met with a ratio of 2.46 to 1.00.

DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement have two financial covenants. 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 ratio 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 ratio may not be greater than 0.75 to 1.00 at any time, except that (a) prior to the amendment described below, this covenant would have been suspended between January 1, 2017 and December 31, 2017, if during this same time DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million or (b) this financial covenant shall be suspended at any time DP&L maintains a rating of BBB- (or in the case of Moody’s 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. This 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 shareholder’s equity 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 (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 September 30, 2017 is 0.46 to 1.00. The amendment also changed, for each agreement, the dates after generation separation during which compliance with the Total Capitalization ratio detailed above shall be suspended if DP&L's long-term indebtedness, as required by the PUCO, is less than or equal to $750.0 million. This time period was originally January 1, 2017 to December 31, 2017, but is now the twelve months immediately subsequent to the separation of the generation assets from DP&L.

The DP&L revolving credit facility and Bond Purchase and Covenants Agreement also have an EBITDA to Interest Expense financial covenant that 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. 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 cannot be less than 2.50 to 1.00. As of September 30, 2017, this covenant was met with a ratio of 7.61 to 1.00.


Debt and Credit Ratings
The following table presents, as of the filing of this report, the debt ratings and outlook for DPL and DP&LAES Ohio, along with the effective or affirmed date of each rating.
DPLDP&LAES OhioOutlookEffective or Affirmed
Fitch Ratings
BBB-BB (a) / BB+(b)
BBB+ (c)(b)
PositiveOctober 2017Negative
Moody's Investors Service, Inc.
Ba3 (b)Ba1 (a)
Baa2 (c)A3 (b)
PositiveOctober 2017Negative
Standard & Poor's Financial Services LLC
BB- (b)BB+ (a)
BBB- (c)BBB+ (b)
StableOctober 2017Developing

(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.



a.Rating relates to DPL's senior unsecured debt.

b.Rating relates to AES Ohio’s senior secured debt.
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The following table presents, as of the filing of this report, the credit ratings (issuer/corporate rating) and outlook for DPL and DP&LAES Ohio, along with the effective or affirmed date of each rating.
DPLDP&LAES OhioOutlookEffective or Affirmed
Fitch RatingsBBBBB-PositiveOctober 2017Negative
Moody's Investors Service, Inc.Ba3Ba1Baa3Baa2PositiveOctober 2017Negative
Standard & Poor's Financial Services LLCBB-BB+BB-BB+StableOctober 2017Developing


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


Off-Balance Sheet Arrangements
For information on guarantees, commercial commitments, and contractual obligations, see Part I, Item 1, Note 9 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL's Condensed Consolidated Financial Statements and Part I, Item 1, Note 10 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DPL’s Condensed Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies of Notes to DP&L’sAES Ohio's Condensed Financial Statements.


MARKET RISK


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

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


The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile thandisclosures presented in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2017 under contract; sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel coststhis section are affected by changes in volume and price and are driven bybased upon a number of variables including weather,assumptions; actual effects may differ. The safe harbor provided in Section 27A of the wholesaleSecurities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this section. For further information regarding market risk, see Item 1A.—Risk Factors and Item 7A - Quantitative and Qualitative Disclosures about Market Risk of our Form 10-K. Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix.

For purposes of potential risk analysis, we userisks associated with the electricity markets, which could have a sensitivity analysis to quantify potential impacts of market rate changesmaterial adverse effect on the statements ofour results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.

Commodity Derivatives
To minimize the risk of fluctuations in the market price of commodities, such as coal, power, natural gas and heating oil, we may enter into commodity-forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the

operations,

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commodity. Cash proceeds or payments between the counter-partyfinancial condition and us at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally docash flows. In addition, we may not enter into forward contracts beyond thirty-six months.

A 10% increase or decrease in the market price ofbe adequately hedged against our FTRs at September 30, 2017 would be immaterial.

At September 30, 2017, a 10% increase or decrease in the market price of our net forward power contracts and net natural gas contracts would result in a net impact on unrealized gains/losses of $(0.6) million and $0.7 million, respectively.

Wholesale Revenues
Energy in excess of contracted obligations is sold in the wholesale spot market when we can identify opportunities with positive margins. The following table presents the percentages of DPL’s and DP&L’s electric revenue derived from wholesale sales.
DPL Nine months ended
  September 30,
  2017 2016
Percent of electric revenues from wholesale market 32% 34%
     
DP&L Nine months ended
  September 30,
  2017 2016
Percent of electric revenues from wholesale market 32% 34%

The closure of Stuart and Killen on or before June 1, 2018 and the agreement to sell DP&L's ownership interest in Zimmer and Miami Fort will limit market exposure to wholesale power prices in future years. See Note 4 – Property, Plant and Equipment of Notes to DPL's Condensed Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L's Condensed Financial Statements.

The following table presents the effect on annual Net income (net of estimated income taxes at 35%) as of September 30, 2017, of a hypothetical increase or decrease of 10% in the price per MWh of wholesale power:
$ in millions DPL DP&L
Effect of 10% change in price per MWh $26.6
 $25.4

Capacity Revenues and Costs
As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year that runs from June 1 to May 31, has conducted auctions for capacity through the delivery year. The clearing prices for capacity during the PJM delivery periods from 2016/17 through 2020/21 are as follows:
  PJM Delivery Year
($/MW-day) 2016/17 2017/18 2018/19 2019/20 2020/21
Capacity clearing price $134
 $152
 $165
 $100
 $77

Our computed average capacity prices by calendar year are reflected in the following table:
  Calendar Year
($/MW-day) 2016 2017 2018 2019 2020
Computed average capacity price $135
 $145
 $159
 $127
 $87

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 RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJM’s RPM business rules.


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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 following table provides estimates of the effect on annual Net income (net of estimated income taxes at 35%) as of September 30, 2017 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will be recovered through the development of our overall energy pricing for customers.
$ in millions DPL DP&L
Effect of $10/MW-day change in capacity auction pricing $5.7
 $4.8

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.

Fuel and Purchased Power Costs
DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the nine months ended September 30, 2017 were 40% and 41%, respectively. We have a significant portion of projected 2017 fuel needs under contract. Most 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 generation plant mix.interest rates.

We purchase power for our SSO load sourced through the competitive bid process and to serve the load of other parties through their competitive bid process. 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 following table provides the effect on annual Net income (net of estimated income taxes at 35%) as of September 30, 2017 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 $18.9
 $17.5


Interest Rate Risk
Because 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 has fixed-rate and variable-rate long-term debt.DPL’s variable-rate debt consists of a $106.3 million term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s variable-rate debt is comprised of bank held tax exempt bonds and a variable rate term loan B. The variable-rate bonds and term loan B bear interest based on an underlying interest rate index, typically LIBOR. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 7 – Long-term Debt of Notes to DPL’s Condensed Consolidated Financial Statements and Note 7 – Long-term Debt of Notes to DP&L’s Condensed Financial Statements.

We have 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 $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


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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.

Principal Payments and Interest Rate Detail by Contractual Maturity Date
The principal value of DPL’s long-term debt was $1,761.5 million at September 30, 2017, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt bonds and the Wright-Patterson Air Force Base note. All of DPL’s long-term debt was adjusted to fair value at the date of the Merger. The fair value of this long-term debt at September 30, 2017 was $1,843.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s long-term debt obligations that are sensitive to interest rate changes:
DPL                
  Principal payments due At September 30, 2017
  during the twelve months ending   
  September 30,   Principal Fair
$ in millions 2018 2019 2020 2021 2022 Thereafter Amount Value
Long-term debt (a)
                
Variable-rate debt $29.5
 $29.5
 $60.8
 $4.5
 $423.7
 $—
 $548.0
 $548.0
Average interest rate (b)
 4.1% 4.1% 4.0% 4.5% 4.5% —%    
Fixed-rate debt (c)
 $0.1
 $0.2
 $400.2
 $0.2
 $780.2
 $32.6
 1,213.5
 1,295.8
Average interest rate 4.2% 4.2% 4.3% 4.2% 7.2% 6.1%    
Total             $1,761.5
 $1,843.8
(a)Amounts exclude immaterial capital lease obligations
(b)
Based on rates in effect at September 30, 2017
(c)
Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DPL's Condensed Consolidated Financial Statements

The principal value of DP&L’s long-term debt was $659.6 million at September 30, 2017, consisting of its first mortgage bonds, tax-exempt bonds and the Wright-Patterson Air Force Base note. The fair value of this long-term debt was $659.5 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. DP&L’s debt was not revalued as a result of the Merger.
DP&L                
  Principal payments due At September 30, 2017
  during the twelve months ending   
  September 30,   Principal Fair
$ in millions 2018 2019 2020 2021 2022 Thereafter Amount Value
Long-term debt (a)
                
Variable-rate debt $4.5
 $4.5
 $4.5
 $4.5
 $423.7
 $—
 $441.7
 $441.7
Average interest rate (b)
 4.5% 4.5% 4.5% 4.5% 4.5% —%    
Fixed-rate debt (c)
 $0.1
 $0.2
 $200.2
 $0.2
 $0.2
 $17.0
 217.9
 217.8
Average interest rate 4.2% 4.2% 1.8% 4.2% 4.2% 4.2%    
Total             $659.6
 $659.5
(a)Amounts exclude immaterial capital lease obligations
(b)
Based on rates in effect at September 30, 2017
(c)
Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DP&L's Condensed Financial Statements


Long-term debt maturities and repayments occurring in the next twelve months are discussed under "CAPITAL RESOURCES AND LIQUIDITY".


Long-term Debt Interest Rate Risk Sensitivity Analysis
Our estimate of market risk exposure is presented for our fixed-rate and variable-rate long-term debt at September 30, 2017 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any


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expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of September 30, 2017, we did not hold any market risk sensitive instruments that were entered into for trading purposes.

The following tables present the carrying value and fair value of our long-term debt, along with the impact of a change of one percent in interest rates:
DPL At September 30, 2017 One percent
  Principal Fair interest rate
$ in millions Amount Value risk
Long-term debt (a)
      
Variable-rate debt $548.0
 $548.0
 $5.5
       
Fixed-rate debt (b)
 1,213.5
 1,295.8
 12.1
       
Total $1,761.5
 $1,843.8
 $17.6
(a)Amounts exclude immaterial capital lease obligations
(b)
Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DPL's Condensed Consolidated Financial Statements

DP&L At September 30, 2017 One percent
  Principal Fair interest rate
$ in millions Amount Value risk
Long-term debt (a)
      
Variable-rate debt $441.7
 $441.7
 $4.4
       
Fixed-rate debt (b)
 217.9
 217.8
 2.2
       
Total $659.6
 $659.5
 $6.6
(a)Amounts exclude immaterial capital lease obligations
(b)
Fixed-rate debt includes $200.0 millionDP&L Tax-exempt First Mortgage Bonds, which are variable rate, that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DP&L's Condensed Financial Statements

DPL’s long-term 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 $1,295.8 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 $548.0 million variable-rate long-term debt outstanding as of September 30, 2017.

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 $217.8 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact of an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $441.7 million variable-rate long-term debt outstanding as of September 30, 2017.

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


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Critical Accounting Estimates


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


Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivablescredit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits and intangible assets. Refer to our Form 10-K for the year ended December 31, 20162020 for a complete listing of our critical accounting policies and estimates. ThereWe have been no material changes toreviewed and determined that these remain as critical accounting policies as of and estimates.for the three months ended March 31, 2021.


ELECTRIC SALES AND CUSTOMERS (a)
  DPLDP&L
  Three months endedThree months ended
  September 30,September 30,
  2017201620172016
Electric Sales (millions of kWh) 3,975
4,810
3,836
4,586
      
Billed electric customers (end of period) 520,211
517,607
520,211
517,607
      
      
  Nine months endedNine months ended
  September 30,September 30,
  2017201620172016
Electric Sales (millions of kWh) 11,396
12,753
11,061
12,242
      
Billed electric customers (end of period) 520,211
517,607
520,211
517,607

(a)This table contains wholesale sales in the PJM market and to other utilities.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk


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


Item 4 – Controls and Procedures


Disclosure Controls and Procedures
OurDPL and AES Ohio, under the supervision and with the participation of its management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining, evaluated the effectiveness of our disclosure“disclosure controls and procedures. These controls and procedures, were designed to ensure that material information relating to us and our subsidiaries” as such term is communicated todefined in Rule 13a-15(e) under the CEO and CFO. We evaluated these disclosure controls and proceduresSecurities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this report with the participation of our CEO and CFO.Quarterly Report on Form 10-Q. Based on thisthat evaluation, our CEO and CFO concluded that as of September 30, 2017, our disclosure controls and procedures were effective as of March 31, 2021, to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.




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Changes in Internal Controls over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Management assessed the effectiveness of our internal control over financial reporting as of September 30, 2017. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”) in 2013.— There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management and our Boards

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Part II – Other Information


Item 1 – Legal Proceedings


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


Our Form 10-K for the fiscal year ended December 31, 2016 and Forms 10-Q for the quarters ended June 30, and March 31, 20172020 and the Notes to DPL’s Consolidated Financial Statements and DP&L’sAES Ohio’s Financial Statements included therein contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such FormsForm 10-K, and 10-Q, and should be read in conjunction with such Forms 10-K and 10-Q.Form 10-K.


The following information is incorporated by reference into this Item: information about the legal proceedings contained in Part I, Item 2 - Management’s– Management's Discussion and Analysis of Financial Condition and Results of Operations and Part I, Item 1, Note 3 – Regulatory Matters of Notes to DPL's Condensed Consolidated Financial Statements and Part I, Item 1, Note 3 – Regulatory Matters of Notes to DP&L'sAES Ohio's Condensed Financial Statements of this Quarterly Report on Form 10-Q.


Item 1A – Risk Factors


A listing of the risk factors that we consider to be the most significant to a decision to invest in our securities is provided in our Form 10-K for the fiscal year ended December 31, 2016. As of September 30, 2017, thereThere have been no material changes with respect to the risk factors as previously disclosed in our Form 10-K. If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.


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

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


None




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Item 3 – Defaults Upon Senior Securities


None


Item 4 – Mine Safety Disclosures


Not applicable.


Item 5 – Other Information


None



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Table of Contents

Item 6 – Exhibits
DPL Inc.DP&LExhibit NumberExhibitLocation
XX2.131(a)Asset Contribution Agreement, dated as of September 28, 2017, by and between The Dayton Power and Light Company and AES Ohio Merger Sub, LLC
Exhibit 2.1 to Report on Form 8-K filed on October 2, 2017 (File No. 1-09052)
XX2.2Agreement and Plan of Merger, dated as of September 28, 2017, by and between AES Ohio Merger Sub, LLC and AES Ohio Generation, LLC
Exhibit 2.2 to Report on Form 8-K filed on October 2, 2017 (File No. 1-09052)
XX4.1
Fifty-First Supplemental Indenture dated as of September 29, 2017 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company

Exhibit 4.1 to Report on Form 8-K filed on October 2, 2017 (File No. 1-09052)
X31(a)Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X31(b)Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X31(c)Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X31(d)Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X32(a)Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
X32(b)Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
X32(c)Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
X32(d)Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
XX101.INSXBRL InstanceFiled herewith as Exhibit 101.INS    
XX101.SCHXBRL Taxonomy Extension SchemaFiled herewith as Exhibit 101.SCH    
XX101.CALXBRL Taxonomy Extension Calculation LinkbaseFiled herewith as Exhibit 101.CAL
XX101.DEFXBRL Taxonomy Extension Definition LinkbaseFiled herewith as Exhibit 101.DEF    
XX101.LABXBRL Taxonomy Extension Label LinkbaseFiled herewith as Exhibit 101.LAB    
XX101.PREXBRL Taxonomy Extension Presentation LinkbaseFiled herewith as Exhibit 101.PRE    


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




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113

SIGNATURES


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

DPL Inc.
(Registrant)
Date:May 5, 2021DPL Inc./s/ Gustavo Garavaglia
(Registrant)Gustavo Garavaglia
Date:November 1, 2017/s/ Kenneth J. Zagzebski
Kenneth J. Zagzebski
President and Chief Executive Officer
(principal executive officer)
November 1, 2017/s/ Craig L. Jackson
Craig L. Jackson
Chief Financial Officer
(principal financial officer)
November 1, 2017May 5, 2021/s/ Kurt A. TornquistJon S. Byers
Kurt A. TornquistJon S. Byers
Controller
(principal accounting officer)


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114

SIGNATURES


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

The Dayton Power and Light Company
(Registrant)
Date:May 5, 2021The Dayton Power and Light Company/s/ Gustavo Garavaglia
(Registrant)Gustavo Garavaglia
Date:November 1, 2017/s/ Thomas A. Raga
Thomas A. Raga
Vice President and Chief ExecutiveFinancial Officer
(principal executive officer)
November 1, 2017/s/ Craig L. Jackson
Craig L. Jackson
Chief Financial Officer
(principal financial officer)
November 1, 2017May 5, 2021/s/ Kurt A. TornquistJon S. Byers
Kurt A. TornquistJon S. Byers
Controller
(principal accounting officer)


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