UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q


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

SECURITIES EXCHANGE ACT OF 1934


For the quarterly period ended March 31,September 30, 2015


OR


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

THE SECURITIES EXCHANGE ACT OF 1934


For the transition period from ____________ to ____________



Commission

File Number

Registrant, State of Incorporation,

Address and Telephone Number


I.R.S. Employer


Identification No.

1-9052

DPL INC.

31-1163136

(An Ohio Corporation)

1065 Woodman Drive

Dayton, Ohio 45432

937-224-6000

1-2385

THE DAYTON POWER AND LIGHT COMPANY

31-0258470

(An Ohio Corporation)

1065 Woodman Drive

Dayton, Ohio 45432

937-224-6000


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


DPL Inc.

Yes ☐

o

No ☒

x

The Dayton Power and Light Company

Yes ☐

o

No ☒

x

DPL Inc. and


The Dayton Power and Light Company areis a voluntary filersfiler that havehas filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.

During the relevant period in 2015, DPL Inc. was a voluntary filer until its May 29, 2015 Registration Statement on Form S-4 filed with the Securities and Exchange Commission was declared effective on June 12, 2015. DPL Inc. has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.


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


DPL Inc.

Yes ☒

No ☐

DPL Inc.

Yes x
No o
The Dayton Power and Light Company

Yes ☒

x

No ☐

o



1


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

Large

accelerated
filer

Accelerated
filer

Non-

accelerated
filer

Smaller

reporting
company

DPL Inc.

accelerated

o

Accelerated

o

accelerated

x

reporting

o

filer

filer

filer

company

DPL Inc.

☐

☐

☒

☐

The Dayton Power and Light Company

☐

o

☐

o

☒

x

☐

o


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

DPL Inc.

Yes ☐

No ☒

DPL Inc.

Yes o
No x
The Dayton Power and Light Company

Yes ☐

o

No ☒

x


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


As of May 8,November 4, 2015, each registrant had the following shares of common stock outstanding:

Registrant

Description

Shares Outstanding

DPL Inc.

Common Stock, no par value

1

The Dayton Power and Light Company

Common Stock, $0.01 par value

41,172,173


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




2


DPL Inc. and The Dayton Power and Light Company

Table of Contents
Quarterly Report on Form 10-Q
Quarter Ended September 30, 2015

DPL Inc. and The Dayton Power and Light Company

Page No.

Table of Contents

Quarterly Report on Form 10-Q

Quarter Ended March 31, 2015

Page No.

Glossary of Terms

5

Part I Financial Information

Item 1

Financial Statements – DPL Inc. and The Dayton Power and Light Company (Unaudited)

DPL Inc.

Condensed Consolidated Statements of Operations

12

10

Condensed Consolidated Statements of Comprehensive Income / (Loss)


13

11

Condensed Consolidated Balance Sheets
12
Condensed Consolidated Statements of Cash Flows

14

Condensed Consolidated Balance Sheets

15

Notes to Condensed Consolidated Financial Statements

17

15

The Dayton Power and Light Company

Condensed Statements of Operations

41

42

Condensed Statements of Comprehensive Income

42

43

Condensed Balance Sheets
44
Condensed Statements of Cash Flows

43

46

Condensed Balance Sheets

44

Notes to Condensed Financial Statements

46

47

Item 2

Management’s Discussion and Analysis of Financial Condition and Operations

64

67

Electric Sales and Customers

83

92

Item 3

Quantitative and Qualitative Disclosures about Market Risk

84

92

Item 4

Controls and Procedures

84

93



3


DPL Inc. and The Dayton Power and Light Company

Table of Contents (cont.)
Quarterly Report on Form 10-Q
Quarter Ended September 30, 2015

DPL Inc. and The Dayton Power and Light Company

Page No.

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

Quarter Ended March 31, 2015

Page No.

Part II Other Information

Item 1

Legal Proceedings

84

93

Item 1A

Risk Factors

85

94

Item 2

Unregistered Sales of Equity Securities and Use of Proceeds

85

94

Item 3

Defaults Upon Senior Securities

85

94

Item 4

Mine Safety Disclosures

85

94

Item 5

Other Information

85

94

Item 6

Exhibits

86

95

Other

Signatures

88

96



4

Table of Contents


GLOSSARY OF TERMS 


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

Term

Definition

AEP Generation

AES

AEP Generation Resources Inc., a subsidiary of American Electric Power Company, Inc. (“AEP”).  Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011. 

AER

Alternative Energy Rider allows DP&L to recover costs related to meeting the Ohio renewable portfolio standards.

AES

The AES Corporation, a global power company and the ultimate parent company of DPL 

AOCI

Accumulated Other Comprehensive Income

ARO

Asset Retirement Obligation

ASU

Accounting Standards Update

CAA

U.S. Clean Air Act

CO2

Carbon Dioxide

CRES

Competitive Retail Electric Service

CWA

DPL

Clean Water Act

DPL Inc.

DPL

DPLE

DPL Inc.

DPLE

DPL Energy, LLC, a wholly owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales

DPLER

DPL Energy Resources, Inc., a wholly owned subsidiary of DPL that sells competitive electric energy and other energy services

DP&L

The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility that delivers electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio

EBITDA

Earnings before interest, taxes, depreciation and amortization

EGU

Electric generating unit

ERISA

The Employee Retirement Income Security Act of 1974

ESP

FASB

Electric Security Plans filed with the PUCO, pursuant to Ohio law

FASB

Financial Accounting Standards Board

FASC

FASB Accounting Standards Codification

FASC 805

FERC

FASB Accounting Standards Codification 805, “Business Combinations”

FERC

Federal Energy Regulatory Commission

FGD

Flue Gas Desulfurization

Form 10-K

DPL’s and DP&L’s combined Annual Report on Form 10-K for the fiscal year ended December 31, 2014, which was filed on February 25, 2015

First and Refunding Mortgage

DP&L’s First and Refunding Mortgage, dated October 1, 1935, as amended, with the Bank of New York Mellon as Trustee

FTR

FTRs

Financial Transmission Rights

GAAP

5

Table of Contents

GLOSSARY OF TERMS (cont.) 

Term

Definition

GAAP

Generally Accepted Accounting Principles in the United States of America

GHG

Greenhouse Gas

kV

Kilovolts,Kilovolt, 1,000 volts

kWh

Kilowatt hours

Kilowatt-hours

LIBOR

London Inter-Bank Offering Rate

Master Trust

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans

MATS

Mercury and Air Toxics Standard
MC Squared

MC Squared Energy Services, LLC, a retail electricity supplier previously wholly owned by DPLER. This subsidiary was sold effective April 1, 2015.

Merger

The 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.

MRO

MTM

Market Rate Option, a plan available to be filed with the PUCO pursuant to Ohio law

MTM

Mark to Market

MVIC

Miami Valley Insurance Company, a wholly owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries and, in some cases, insurance services to partner companies related to jointly owned facilities operated by DP&L

MW

Megawatt

MWh

Megawatt hour

Megawatt-hour

NERC

NAAQS

National Ambient Air Quality Standards



5
Table of Contents

GLOSSARY OF TERMS (cont.)
TermDefinition
NERCNorth American Electric Reliability Corporation

Non-bypassable

NOx

Charges that are assessed to all customers regardless of whom the customer selects as their retail electric generation supplier 

Nitrogen Oxide

NOV

NPDES

Notice of Violation

NOx

Nitrogen Oxide

NPDES

National Pollutant Discharge Elimination System

NYMEX

NSPS

New Source Performance Standards

NYMEXNew York Mercantile Exchange

OCC

Ohio Consumers’ Counsel

OCI

Other Comprehensive Income

Ohio EPA

Ohio Environmental Protection Agency

OTC

Over-The-Counter

OVEC

Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest

PJM

PJM Interconnection, LLC, an RTO

PPM

PRP

Parts Per Million

PRP

Potentially Responsible Party

PUCO

Public Utilities Commission of Ohio

RCRA

6

Table of Contents

U.S. Resource Conservation and Recovery Act

GLOSSARY OF TERMS (cont.) 

Term

RPM

Definition

RPM

Reliability Pricing Model. The Reliability Pricing Model is PJM’s capacity construct. The purpose of the RPM is to enable PJM to obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. Under the RPM construct, PJM procures capacity, through a multi-auction structure, on behalf of the load serving entities to satisfy the load obligations. There are three RPM auctions held for each delivery year (running from June 1 through May 31). The base residual auction is held three years in advance of the delivery year and then there is one incremental auction held in each of the subsequent three years. DP&L’s capacity is located in the “rest of” RTO area of PJM.

RTO

Regional Transmission Organization

SB 221

SCR

Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008.  This law required all Ohio distribution utilities to file either an ESP or MRO to be in effect January 1, 2009.  The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.

SCR

Selective Catalytic Reduction

SEC

Securities and Exchange Commission

SERP

Supplemental Executive Retirement Plan

Service Company

AES US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses

SIP

SO2

A State Implementation Plan is a plan for complying with the federal CAA, administered by the USEPA. The SIP consists of narrative, rules, technical documentation and agreements that an individual state will use to clean up polluted areas.

Sulfur Dioxide

SO2

SSO

Sulfur Dioxide

SO3

Sulfur Trioxide

SSO

Standard Service Offer represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers that take retail generation service from DP&L within DP&L’s service territory

SSR

USEPA

Service Stability Rider

USEPA

U.S. Environmental Protection Agency

USF

The Universal Service Fund (USF) is a statewide program which provides qualified low-income customers in Ohio with income-based bills and energy efficiency education programs

U.S. SBU

U. S. Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL

7




6

Table of Contents


FORWARD-LOOKING STATEMENTS


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

·

abnormal or severe weather and catastrophic weather-related damage;

·

unusual maintenance or repair requirements;


·

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

abnormal or severe weather and catastrophic weather-related damage;

·

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

unusual maintenance or repair requirements;

·

increased competition and deregulation in the electric utility industry;

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

·

increased competition in the retail generation market;

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

·

availability and price of capacity;

increased competition and deregulation in the electric utility industry;

·

changes in interest rates;

increased competition in the retail generation market;

·

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

availability and price of capacity;

·

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

changes in interest rates;

·

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

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

·

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

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

·

significant delays associated with large construction projects;

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

·

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

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

·

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

significant delays associated with large construction projects;

·

financial market conditions;

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

·

changes in tax laws and the effects of our strategies to reduce tax payments;

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

·

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

financial market conditions;

·

general economic conditions; and

changes in tax laws and the effects of our strategies to reduce tax payments;

·

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

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

general economic conditions; and
the risks and other factors discussed in this report and other DPL and DP&L filings with the SEC.

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


All such factors are difficult to predict, contain uncertainties that may materially affect actual results and many are beyond our control. See “Risk Factors” for a more detailed discussion of the foregoing and certain other

8

Table of Contents

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.



7
Table of Contents


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


COMPANY WEBSITES


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

9

Table of Contents

Part I – Financial Information

Part I – Financial Information

This report includes the combined filing of DPL and DP&L. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPLand 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

10

Item 1 – Financial Statements


8

Table of Contents














FINANCIAL STATEMENTS


DPL INC.

11




9

Table of Contents


DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
         
Revenues $414.1
 $479.2
 $1,281.5
 $1,329.6
         
Cost of revenues:        
Fuel 71.4
 85.1
 202.2
 235.9
Purchased power 145.4
 153.7
 460.2
 466.2
Amortization of intangibles —
 0.3
 —
 0.9
Total cost of revenues 216.8
 239.1
 662.4
 703.0
         
Gross margin 197.3
 240.1
 619.1
 626.6
         
Operating expenses:        
Operation and maintenance 101.4
 94.0
 281.5
 294.7
Depreciation and amortization 34.8
 34.5
 104.1
 103.7
General taxes 20.8
 21.2
 67.8
 70.3
Goodwill impairment —
 —
 —
 135.8
Fixed-asset impairment —
 —
 —
 11.5
Other —
 (0.1) (0.3) 1.3
Total operating expenses 157.0
 149.6
 453.1
 617.3
         
Operating income 40.3
 90.5
 166.0
 9.3
         
Other income / (expense), net        
Investment income / (loss) 0.1
 0.2
 0.1
 0.6
Interest expense (28.9) (33.1) (90.3) (95.8)
Charge for early retirement of debt (2.1) (0.1) (2.1) —
Other expense (0.5) (0.1) (1.2) (1.2)
Total other expense, net (31.4) (33.1) (93.5) (96.4)
         
Earnings / (loss) before income taxes 8.9
 57.4
 72.5
 (87.1)
         
Income tax expense / (benefit) 0.3
 (41.0) 13.5
 29.7
         
Net income / (loss) $8.6
 $98.4
 $59.0
 $(116.8)

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


10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

Three months ended March 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Revenues

 

$

494.5 

 

$

460.3 

 

 

 

 

 

 

 

Cost of revenues:

 

 

 

 

 

 

Fuel

 

 

76.4 

 

 

90.0 

Purchased power

 

 

194.2 

 

 

174.1 

Amortization of intangibles

 

 

 -

 

 

0.3 

Total cost of revenues

 

 

270.6 

 

 

264.4 

 

 

 

 

 

 

 

Gross margin

 

 

223.9 

 

 

195.9 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

Operation and maintenance

 

 

91.7 

 

 

104.7 

Depreciation and amortization

 

 

35.0 

 

 

35.3 

General taxes

 

 

24.1 

 

 

27.6 

Goodwill impairment

 

 

 -

 

 

135.8 

Fixed-asset impairment

 

 

 -

 

 

11.5 

Other

 

 

0.5 

 

 

0.3 

Total operating expenses

 

 

151.3 

 

 

315.2 

 

 

 

 

 

 

 

Operating income / (loss)

 

 

72.6 

 

 

(119.3)

 

 

 

 

 

 

 

Other income / (expense), net:

 

 

 

 

 

 

Investment income / (loss)

 

 

(0.2)

 

 

0.4 

Interest expense

 

 

(30.5)

 

 

(30.8)

Other expense

 

 

(0.5)

 

 

(0.5)

Total other expense

 

 

(31.2)

 

 

(30.9)

 

 

 

 

 

 

 

Earnings / (loss) before income taxes

 

 

41.4 

 

 

(150.2)

 

 

 

 

 

 

 

Income tax expense

 

 

12.7 

 

 

98.8 

 

 

 

 

 

 

 

Net income / (loss)

 

$

28.7 

 

$

(249.0)

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

12

Table of Contents


DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)
  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
Net income / (loss) $8.6
 $98.4
 $59.0
 $(116.8)
Available-for-sale securities activity:        
Change in fair value of available-for-sale securities, net of income tax benefit of $0.1, $0.2, $0.1 and $0.2 for each respective period (0.3) (0.4) (0.2) (0.6)
Reclassification to earnings, net of income tax expense of $0.0, $(0.1), $0.0 and $(0.2) for each respective period —
 0.2
 —
 0.4
Total change in fair value of available-for-sale securities (0.3) (0.2) (0.2) (0.2)
Derivative activity:        
Change in derivative fair value, net of income tax (expense) / benefit of $(4.4), $(1.0), $(5.4) and $12.4 for each respective period 7.8
 1.2
 9.6
 (23.8)
Reclassification to earnings, net of income tax (expense) / benefit of $1.1, $(1.5), $1.6 and $(7.4) for each respective period (2.0) 3.4
 (3.4) 14.2
Total change in fair value of derivatives 5.8
 4.6
 6.2
 (9.6)
Pension and postretirement activity:        
Reclassification to earnings, net of income tax expense of $0.0, $0.0, $(0.4) and $0.0 for each respective period 0.1
 —
 (0.1) —
Total change in unfunded pension obligation 0.1
 —
 (0.1) —
Other comprehensive income / (loss) 5.6
 4.4
 5.9
 (9.8)
         
Net comprehensive income / (loss) $14.2
 $102.8
 $64.9
 $(126.6)

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



11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

 

 

Three months ended March 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Net income / (loss)

 

$

28.7 

 

$

(249.0)

 

 

 

 

 

 

 

Available-for-sale securities activity:

 

 

 

 

 

 

Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $(0.3) and $0.2 for each respective period

 

 

0.5 

 

 

(0.3)

Reclassification to earnings, net of income tax (expense) / benefit of $0.2 and $(0.1) for each respective period

 

 

(0.4)

 

 

0.2 

Total change in fair value of available-for-sale securities

 

 

0.1 

 

 

(0.1)

 

 

 

 

 

 

 

Derivative activity:

 

 

 

 

 

 

Change in derivative fair value, net of income tax (expense) / benefit of $(0.1) and $7.0 for each respective period

 

 

0.1 

 

 

(12.9)

Reclassification to earnings, net of income tax expense of $(0.3) and $(3.1) for each respective period

 

 

0.6 

 

 

5.5 

Total change in fair value of derivatives

 

 

0.7 

 

 

(7.4)

 

 

 

 

 

 

 

Pension and postretirement activity:

 

 

 

 

 

 

Reclassification to earnings, net of income tax expense of $0.0 and $0.0 for each respective period

 

 

0.1 

 

 

 -

Total change in unfunded pension obligation

 

 

0.1 

 

 

 -

 

 

 

 

 

 

 

Other comprehensive income / (loss)

 

 

0.9 

 

 

(7.5)

 

 

 

 

 

 

 

Net comprehensive income / (loss)

 

$

29.6 

 

$

(256.5)

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

13

Table of Contents


DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
  September 30, December 31,
$ in millions 2015 2014
ASSETS    
Current assets:    
Cash and cash equivalents $43.0
 $17.0
Restricted cash 13.6
 16.8
Accounts receivable, net (Note 2) 152.7
 200.9
Inventories (Note 2) 97.0
 100.2
Taxes applicable to subsequent years 19.6
 77.8
Regulatory assets, current 29.4
 44.2
Other prepayments and current assets 44.6
 41.8
Total current assets 399.9
 498.7
Property, plant & equipment:    
Property, plant & equipment 2,879.7
 2,759.3
Less: Accumulated depreciation and amortization (404.3) (318.4)
  2,475.4
 2,440.9
Construction work in process 71.4
 76.7
Total net property, plant & equipment 2,546.8
 2,517.6
Other non-current assets:    
Regulatory assets, non-current 152.4
 167.5
Goodwill 317.0
 317.0
Intangible assets, net of amortization 30.4
 37.4
Other deferred assets 42.9
 39.6
Total other non-current assets 542.7
 561.5
     
Total assets $3,489.4
 $3,577.8

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



12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

Three months ended March 31,

$ in millions

 

2015

 

2014

Cash flows from operating activities:

 

 

 

 

 

 

Net income / (loss)

 

$

28.7 

 

$

(249.0)

Adjustments to reconcile net income / (loss) to net cash from operating activities:

 

 

 

 

 

 

Depreciation and amortization

 

 

35.0 

 

 

35.3 

Amortization of intangibles

 

 

 -

 

 

0.3 

Deferred income taxes

 

 

(1.0)

 

 

(3.2)

Goodwill Impairment

 

 

 -

 

 

135.8 

Fixed-asset impairment

 

 

 -

 

 

11.5 

Changes in certain assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 

 

3.8 

 

 

(13.7)

Inventories

 

 

5.2 

 

 

(8.0)

Prepaid taxes

 

 

0.6 

 

 

1.4 

Taxes applicable to subsequent years

 

 

19.1 

 

 

14.0 

Deferred regulatory costs, net

 

 

11.4 

 

 

(7.7)

Accounts payable

 

 

(20.4)

 

 

36.9 

Accrued taxes payable

 

 

(24.7)

 

 

75.6 

Accrued interest payable

 

 

6.8 

 

 

14.5 

Pension, retiree and other benefits

 

 

2.0 

 

 

0.8 

Other

 

 

(0.6)

 

 

(31.6)

Net cash from operating activities

 

 

65.9 

 

 

12.9 

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

 

Capital expenditures

 

 

(33.7)

 

 

(28.4)

Purchase of emission allowances

 

 

 -

 

 

(0.1)

Purchase of renewable energy credits

 

 

(0.2)

 

 

(1.2)

Decrease / (increase) in restricted cash

 

 

(0.8)

 

 

(15.6)

Other investing activities, net

 

 

0.3 

 

 

 -

Net cash from investing activities

 

 

(34.4)

 

 

(45.3)

 

 

 

 

 

 

 

Net cash from financing activities:

 

 

 

 

 

 

Borrowings from revolving credit facilities

 

 

15.0 

 

 

65.0 

Repayment of borrowings from revolving credit facilities

 

 

(15.0)

 

 

(65.0)

Net cash from financing activities

 

 

 -

 

 

 -

 

 

 

 

 

 

 

Cash and cash equivalents:

 

 

 

 

 

 

Net change

 

 

31.5 

 

 

(32.4)

Balance at beginning of period

 

 

17.0 

 

 

53.2 

Cash and cash equivalents at end of period

 

$

48.5 

 

$

20.8 

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

 

Interest paid, net of amounts capitalized

 

$

20.8 

 

$

15.0 

Income taxes paid / (refunded), net

 

$

 -

 

$

(0.3)

Non-cash financing and investing activities:

 

 

 

 

 

 

Accruals for capital expenditures

 

$

11.2 

 

$

9.4 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

14

Table of Contents


DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
  September 30, December 31,
$ in millions 2015 2014
LIABILITIES AND SHAREHOLDER'S EQUITY    
Current liabilities:    
Current portion of long-term debt (Note 5) $444.9
 $20.1
Short-term debt 10.0
 —
Accounts payable 85.7
 109.2
Accrued taxes 140.8
 102.6
Accrued interest 31.1
 27.2
Security deposits 33.8
 14.4
Regulatory liabilities, current 20.5
 4.4
Insurance and claims costs 5.6
 6.4
Other current liabilities 48.4
 48.7
Total current liabilities 820.8
 333.0
Non-current liabilities:    
Long-term debt (Note 5) 1,564.5
 2,139.6
Deferred taxes 556.0
 587.3
Taxes payable 3.4
 80.9
Regulatory liabilities, non-current 125.6
 124.1
Pension, retiree and other benefits 91.2
 95.9
Unamortized investment tax credit 1.9
 2.2
Other deferred credits 94.2
 48.2
Total non-current liabilities 2,436.8
 3,078.2
     
Redeemable preferred stock of subsidiary 18.4
 18.4
     
Commitments and contingencies (Note 10) 
 
     
Common shareholder's equity:    
Common stock:    
1,500 shares authorized; 1 share issued and outstanding at September 30, 2015 and December 31, 2014 —
 —
Other paid-in capital 2,237.7
 2,237.4
Accumulated other comprehensive income 13.4
 7.5
Accumulated deficit (2,037.7) (2,096.7)
Total common shareholder's equity 213.4
 148.2
     
Total liabilities and shareholder's equity $3,489.4
 $3,577.8

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


13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

48.5 

 

$

17.0 

Restricted cash

 

 

17.5 

 

 

16.8 

Accounts receivable, net (Note 2)

 

 

180.6 

 

 

200.9 

Inventories (Note 2)

 

 

94.9 

 

 

100.2 

Taxes applicable to subsequent years

 

 

58.7 

 

 

77.8 

Regulatory assets, current

 

 

34.9 

 

 

44.2 

Other prepayments and current assets

 

 

56.7 

 

 

41.8 

Total current assets

 

 

491.8 

 

 

498.7 

 

 

 

 

 

 

 

Property, plant & equipment:

 

 

 

 

 

 

Property, plant & equipment

 

 

2,792.1 

 

 

2,759.3 

Less: Accumulated depreciation and amortization

 

 

(347.1)

 

 

(318.4)

 

 

 

2,445.0 

 

 

2,440.9 

Construction work in process

 

 

65.6 

 

 

76.7 

Total net property, plant & equipment

 

 

2,510.6 

 

 

2,517.6 

 

 

 

 

 

 

 

Other non-current assets:

 

 

 

 

 

 

Regulatory assets, non-current

 

 

156.8 

 

 

167.5 

Goodwill

 

 

317.0 

 

 

317.0 

Intangible assets, net of amortization

 

 

31.7 

 

 

37.4 

Other deferred assets

 

 

46.0 

 

 

39.6 

Total other non-current assets

 

 

551.5 

 

 

561.5 

 

 

 

 

 

 

 

Total assets

 

$

3,553.9 

 

$

3,577.8 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

15

Table of Contents


 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Current portion of long-term debt (Note 4)

 

$

30.1 

 

$

20.1 

Accounts payable

 

 

82.2 

 

 

109.2 

Accrued taxes

 

 

116.6 

 

 

102.6 

Accrued interest

 

 

34.1 

 

 

27.2 

Customer security deposits

 

 

13.7 

 

 

14.4 

Regulatory liabilities, current

 

 

6.8 

 

 

4.4 

Insurance and claims costs

 

 

5.6 

 

 

6.4 

Other current liabilities

 

 

46.1 

 

 

48.7 

Total current liabilities

 

 

335.2 

 

 

333.0 

 

 

 

 

 

 

 

Non-current liabilities:

 

 

 

 

 

 

Long-term debt (Note 4)

 

 

2,129.6 

 

 

2,139.6 

Deferred taxes

 

 

577.8 

 

 

587.3 

Taxes payable

 

 

42.2 

 

 

80.9 

Regulatory liabilities, non-current

 

 

124.6 

 

 

124.1 

Pension, retiree and other benefits

 

 

95.9 

 

 

95.9 

Unamortized investment tax credit

 

 

2.1 

 

 

2.2 

Other deferred credits

 

 

50.2 

 

 

48.2 

Total non-current liabilities

 

 

3,022.4 

 

 

3,078.2 

 

 

 

 

 

 

 

Redeemable preferred stock of subsidiary

 

 

18.4 

 

 

18.4 

 

 

 

 

 

 

 

Commitments and contingencies (Note 9)

 

 

 

 

 

 

 

 

 

 

 

 

 

Common shareholder's equity:

 

 

 

 

 

 

Common stock:

 

 

 

 

 

 

1,500 shares authorized; 1 share issued and outstanding at March 31, 2015 and December 31, 2014

 

 

 -

 

 

 -

Other paid-in capital

 

 

2,237.5 

 

 

2,237.4 

Accumulated other comprehensive income

 

 

8.4 

 

 

7.5 

Accumulated deficit

 

 

(2,068.0)

 

 

(2,096.7)

Total common shareholder's equity

 

 

177.9 

 

 

148.2 

 

 

 

 

 

 

 

Total liabilities and shareholder's equity

 

$

3,553.9 

 

$

3,577.8 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

 

 

 

 

These interim statements are unaudited.

 

 

 

 

 

 

16

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
  Nine months ended September 30,
$ in millions 2015 2014
Cash flows from operating activities:    
Net income / (loss) $59.0
 $(116.8)
Adjustments to reconcile net income / (loss) to net cash from operating activities:    
Depreciation and amortization 104.1
 103.7
Amortization of intangibles —
 0.9
Amortization of debt market value adjustments (1.1) 0.1
Deferred income taxes (20.5) (2.5)
Goodwill Impairment —
 135.8
Fixed-asset impairment —
 11.5
Changes in certain assets and liabilities:    
Accounts receivable 48.8
 12.7
Inventories 3.1
 (3.6)
Prepaid taxes (0.6) 0.5
Taxes applicable to subsequent years 58.2
 52.1
Deferred regulatory costs, net 27.6
 4.8
Accounts payable (15.9) 7.2
Accrued taxes payable (39.2) (27.5)
Accrued interest payable 3.7
 14.5
Security deposits 19.4
 0.5
Pension, retiree and other benefits 1.0
 (5.2)
Other 12.8
 (14.3)
Net cash provided by operating activities 260.4
 174.4
Cash flows from investing activities:    
Capital expenditures (93.5) (81.6)
Proceeds from sale of business 1.3
 —
Purchase of emission allowances —
 (0.2)
Purchase of renewable energy credits (0.6) (3.4)
Increase / (decrease) in restricted cash 3.2
 (9.0)
Other investing activities, net 0.4
 1.1
Net cash used by investing activities (89.2) (93.1)
Net cash from financing activities:    
Payments of deferred financing costs (5.6) (0.3)
Issuance of long-term debt 325.0
 —
Borrowings from revolving credit facilities 70.0
 115.0
Repayment of borrowings from revolving credit facilities (60.0) (115.0)
Retirement of long-term debt (474.5) (30.1)
Other financing activities, net (0.1) —
Net cash used by financing activities (145.2) (30.4)
Cash and cash equivalents:    
Net change 26.0
 50.9
Balance at beginning of period 17.0
 53.2
Cash and cash equivalents at end of period $43.0
 $104.1
Supplemental cash flow information:    
Interest paid, net of amounts capitalized $77.3
 $73.8
Income taxes paid / (refunded), net $0.8
 $0.2
Non-cash financing and investing activities:    
Accruals for capital expenditures $12.6
 $6.7
See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.


14

Table of Contents


DPL Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1.


Note 1 – Overview and Summary of Significant Accounting Policies


Description of Business

DPLis a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER operations, which includeincluded the operations of DPLER’s wholly owned subsidiary MC Squared. MC Squared was sold effective April 1, 2015. See Note 1011 for more information relating to these reportable segments. 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 is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to its more than 516,000 515,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central OhioOhio. DP&L owns multiple coal-fired and generates electricitypeaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at five coal-fired power stations.amortized cost. During 2015, DP&Lis required to source 60% of the generation for its SSO customers through a competitive bid process and beginning January 2016, generation for its SSO customers will be 100% competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. On June 4, 2014, the PUCO issued an entry on rehearing which requires DP&L to separate its generation assets from its transmission and distribution assets no later than January 1, 2017. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.


DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers.customers in Ohio. As of March 31,September 30, 2015, DPLER’s operations include those of its wholly owned subsidiary MC Squared. DPLER has approximately 259,000128,000 customers currently located throughout Ohio and Illinois.  This number includes approximately 116,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier.Ohio. On April 1, 2015, DPLER closed on the sale of its former subsidiary, MC Squared.  After considering the sale of MC Squared on April 1, 2015, the Competitive Retail segment sold electricity to 143,000 customers. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&Lto meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the areas it serves.


DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity, and MVIC, our captive insurance company that provides insurance services to our subsidiaries and us. DPL owns all of the common stock of its subsidiaries.


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


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


DPL and its subsidiaries employed 1,1851,234 people as of March 31,September 30, 2015, of which 1,1661,194 were employed by DP&L. Approximately 60%59% of all DPL employees are under a collective bargaining agreement that expires on October 31, 2017.


Financial Statement Presentation

DPL’s Condensed Consolidated Financial Statements include the accounts of DPL and its wholly owned subsidiaries except for DPL Capital Trust II, which is not consolidated, consistent with the provisions of GAAP. DP&L has undivided ownership interests in five coal-fired generating facilities, various peaking generating


17


15

Table of Contents


facilities and numerous transmission facilities, all of which are included in the financial statements at amortized cost, which was adjusted to fair value at the date of the Merger for DPL. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Consolidated Statements of Operations. See Note 34 for more information.


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.


These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2014. 

10-K.


In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31,September 30, 2015; our results of operations for the three and nine months ended March 31,September 30, 2015 and 2014 and our cash flows for the threenine months ended March 31,September 30, 2015 and 2014.2014. Unless otherwise noted, all adjustments are normal and recurring in nature.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 March 31,September 30, 2015 may not be indicative of our results that will be realized for the full year ending December 31, 2015.


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


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

As a result ofvalue at the sale of MC Squared mentioned above, $0.4 million of cash and $17.4 million of accounts receivable have been reclassified to current assets held for sale, included in “Other prepayments and current assets” in the Condensed Consolidated Balance Sheet at March 31, 2015. Additionally, $0.6 million of property, plant and equipment (net of accumulated depreciation) and $1.4 million of intangible assets (net of amortization) have been reclassified to non-current assets held for sale, included in “Other deferred assets” in the Condensed Consolidated Balance Sheet at March 31, 2015.

Merger date.


Sale of Receivables

DPLER andsells its former subsidiary MC Squared sell their customer receivables. These sales are at a small discount for cash at the billed amounts for their customers’ use of energy. Total receivables sold by DPLER and by MC Squared prior to its sale during the three months ended March 31,September 30, 2015 and 2014 were $33.1$9.4 million and $32.2$37.7 million, respectively.

Total receivables sold by DPLER and by MC Squared prior to its sale during the nine months ended September 30, 2015 and 2014 were $49.1 million and $98.7 million, respectively.


Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DPL collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31,September 30, 2015 and 2014 were $14.0$13.0 million and $14.4$12.5 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2015 and 2014 were $38.5 million and $38.5 million, respectively.


Related Party Transactions

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

DPL charges the Service Company for employee payroll and benefit costs that are incurred on behalf of the Service Company.

18


16

Table of Contents



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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

March 31,

$ in millions

 

2015

 

2014

Transactions with the Service Company

 

 

 

 

 

 

Charges for services provided

 

$

9.8 

 

$

10.4 

 

 

 

 

 

 

 

 

 

 

 

 

 Three months ended Nine months ended
 September 30, September 30,
$ in millions 2015 2014 2015 2014

Transactions with the Service Company

 

At March 31, 2015

 

At December 31, 2014

        

Net advances / (payable) to the Service Company

 

$

3.0 

 

$

(4.7)
Charges from the Service Company $8.9
 $11.7
 $28.5
 $28.4
Charges to the Service Company $1.1
 $0.6
 $5.1
 $1.8
        
     at September 30, 2015 at December 31, 2014
Net prepaid / (payable) to the service companyNet prepaid / (payable) to the service company $0.1
 $(4.7)


DPL has issued debt to a wholly owned business trust, DPL Capital Trust II. See Note 5 for further information.


Recently Issued Accounting Standards


ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of March 31,September 30, 2015, DPL had approximately $20.5$17.6 million in deferred financing costs classified in other noncurrentnon-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

2.


ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contract with Customer (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. We have not yet selected a transition method and we are currently evaluating the impact of adopting the standard on our financial statements.

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

ASU No. 2015-02, Consolidation — Amendments to the Consolidation Analysis (Topic 810)
In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and


17
Table of Contents

interim periods therein. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements.

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

ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. We have not yet selected a transition method and we are currently evaluating the impact of adopting the standard on our financial statements.

Note 2 – Supplemental Financial Information


Accounts receivable and Inventories are as follows at March 31,September 30, 2015 and December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Accounts receivable, net:

 

 

 

 

 

 

Unbilled revenue

 

$

58.6 

 

$

79.2 

Customer receivables

 

 

109.3 

 

 

104.8 

Amounts due from partners in jointly owned plants

 

 

8.3 

 

 

14.2 

Other

 

 

5.8 

 

 

4.0 

Provision for uncollectible accounts

 

 

(1.4)

 

 

(1.3)

Total accounts receivable, net

 

$

180.6 

 

$

200.9 

 

 

 

 

 

 

 

Inventories, at average cost:

 

 

 

 

 

 

Fuel and limestone

 

$

58.9 

 

$

65.3 

Plant materials and supplies

 

 

34.3 

 

 

33.5 

Other

 

 

1.7 

 

 

1.4 

Total inventories, at average cost

 

$

94.9 

 

$

100.2 

19

  September 30, December 31,
$ in millions 2015 2014
Accounts receivable, net:    
Unbilled revenue $49.3
 $79.2
Customer receivables 86.8
 104.8
Amounts due from partners in jointly owned plants 12.0
 14.2
Other 5.6
 4.0
Provision for uncollectible accounts (1.0) (1.3)
Total accounts receivable, net $152.7
 $200.9
Inventories, at average cost:    
Fuel and limestone $60.3
 $65.3
Plant materials and supplies 34.7
 33.5
Other 2.0
 1.4
Total inventories, at average cost $97.0
 $100.2



18

Table of Contents


Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended March 31,September 30, 2015 and 2014 are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Details about Accumulated Other Comprehensive Income / (Loss) components

 

Affected line item in the Condensed Consolidated Statements of Operations

 

Three months ended

 

 

 

 

March 31,

$ in millions

 

 

 

2015

 

2014

 

 

 

 

 

 

 

 

 

Gains and losses on Available-for-sale securities activity (Note 7):

 

 

 

 

 

 

 

 

Other income

 

$

(0.6)

 

$

0.3 

 

 

Tax expense

 

 

0.2 

 

 

(0.1)

 

 

Net of income taxes

 

 

(0.4)

 

 

0.2 

 

 

 

 

 

 

 

 

 

Gains and losses on cash flow hedges (Note 8):

 

 

 

 

 

 

 

 

Interest expense

 

 

(0.2)

 

 

(0.5)

 

 

Revenue

 

 

(0.3)

 

 

10.2 

 

 

Purchased power

 

 

1.4 

 

 

(1.1)

 

 

Total before income taxes

 

 

0.9 

 

 

8.6 

 

 

Tax expense

 

 

(0.3)

 

 

(3.1)

 

 

Net of income taxes

 

 

0.6 

 

 

5.5 

 

 

 

 

 

 

 

 

 

Amortization of defined benefit pension items (Note 6):

 

 

 

 

 

 

 

 

Other income

 

 

0.1 

 

 

 -

 

 

Tax expense

 

 

 -

 

 

 -

 

 

Net of income taxes

 

 

0.1 

 

 

 -

 

 

 

 

 

 

 

 

 

Total reclassifications for the period, net of income taxes

 

$

0.3 

 

$

5.7 

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   2015 2014 2015 2014
Gains and losses on Available-for-sale securities activity (Note 8):      
  Other income $—
 $0.3
 $—
 $0.6
  Tax expense —
 (0.1) —
 (0.2)
  Net of income taxes —
 0.2
 —
 0.4
Gains and losses on cash flow hedges (Note 9):        
  Interest expense (0.2) (0.3) (0.7) (1.0)
  Revenue (3.8) 4.9
 (7.0) 23.4
  Purchased power 0.9
 0.3
 2.7
 (0.8)
  Total before income taxes (3.1) 4.9
 (5.0) 21.6
  Tax expense 1.1
 (1.5) 1.6
 (7.4)
  Net of income taxes (2.0) 3.4
 (3.4) 14.2
Amortization of defined benefit pension items (Note 7):        
  Other income 0.1
 —
 0.3
 —
  Tax expense —
 —
 (0.4) —
  Net of income taxes 0.1
 —
 (0.1) —
           
Total reclassifications for the period, net of income taxes $(1.9) $3.6
 $(3.5) $14.6

The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the threenine months ended March 31,September 30, 2015 are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Gains / (losses) on available-for-sale securities

 

Gains / (losses) on cash flow hedges

 

Change in unfunded pension obligation

 

Total

Balance January 1, 2015

 

$

0.5 

 

$

18.5 

 

$

(11.5)

 

$

7.5 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income before reclassifications

 

 

0.5 

 

 

0.1 

 

 

 -

 

 

0.6 

Amounts reclassified from accumulated other comprehensive income / (loss)

 

 

(0.4)

 

 

0.6 

 

 

0.1 

 

 

0.3 

Net current period other comprehensive income

 

 

0.1 

 

 

0.7 

 

 

0.1 

 

 

0.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance March 31, 2015

 

$

0.6 

 

$

19.2 

 

$

(11.4)

 

$

8.4 

20

$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance January 1, 2015 $0.5
 $18.5
 $(11.5) $7.5
         
Other comprehensive income before reclassifications (0.2) 9.6
 —
 9.4
Amounts reclassified from accumulated other comprehensive income / (loss) —
 (3.4) (0.1) (3.5)
Net current period other comprehensive income / (loss) (0.2) 6.2
 (0.1) 5.9
         
Balance September 30, 2015 $0.3
 $24.7
 $(11.6) $13.4

Note 3 – Regulatory assets and liabilities

DP&L has certain rate riders that provide for recovering, on a timely basis, costs incurred for specific programs for which costs may fluctuate. These riders generally allow DP&L to estimate future costs and customer kWh


19

Table of Contents

3.


consumption and set rider rates designed to recover those estimated costs as they are incurred. Differences between revenues collected and the actual program costs are tracked and reconciled by increasing or reducing future rates accordingly. DP&L’s current regulatory assets and current regulatory liabilities reflect the reconciliation of such differences, with the exception of deferred storm costs. The deferred storm regulatory asset reflects costs incurred to repair major storm damage in previous years, for which DP&L was granted cost recovery during 2015. The changes in DP&L’s current regulatory asset and liability balances from December 31, 2014 to September 30, 2015 primarily represent the recovery of $16.7 million of deferred storm costs, and the reconciliation of other rider costs.

Note 4 – Ownership of Coal-fired Facilities


DP&L has undivided ownership interests in five coal-fired electric generating facilities, various peaking facilities and numerous transmission facilities with certain other Ohio utilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At March 31,September 30, 2015, DP&L had $24.0$25.0 million of construction work in process at such jointly owned facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned units and stations.


DP&L’s undivided ownership interest in such facilities at March 31,September 30, 2015 is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L Share

 

 

DPL Carrying value

Jointly owned production units and stations:

 

Ownership
(%)

 

Summer Production Capacity (MW)

 

Gross Plant in Service
($ in millions)

 

Accumulated Depreciation
($ in millions)

 

Construction Work in Process
($ in millions)

 

SCR and FGD Equipment Installed and in Service (Yes/No)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conesville Unit 4

 

16.5

 

129 

 

$

25 

 

$

2 

 

$

1 

 

Yes

Killen Station

 

67.0

 

402 

 

 

308 

 

 

22 

 

 

4 

 

Yes

Miami Fort Units 7 and 8

 

36.0

 

368 

 

 

214 

 

 

26 

 

 

3 

 

Yes

Stuart Station

 

35.0

 

808 

 

 

220 

 

 

17 

 

 

12 

 

Yes

Zimmer Station

 

28.1

 

371 

 

 

185 

 

 

37 

 

 

4 

 

Yes

Transmission (at varying percentages)

 

 

 

n/a

 

 

42 

 

 

6 

 

 

 -

 

 

Total

 

 

 

2,078 

 

$

994 

 

$

110 

 

$

24 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  DP&L Share DPL Carrying value
Jointly owned production units and stations: 
Ownership
(%)
 Summer Production Capacity (MW) 
Gross Plant in Service
($ in millions)
 
Accumulated Depreciation
($ in millions)
 
Construction Work in Process
($ in millions)
 SCR and FGD Equipment Installed and in Service (Yes/No)
Conesville Unit 4 16.5 129
 $25
 $4
 $1
 Yes
Killen Station 67.0 402
 340
 30
 1
 Yes
Miami Fort Units 7 and 8 36.0 368
 218
 31
 4
 Yes
Stuart Station 35.0 808
 234
 21
 14
 Yes
Zimmer Station 28.1 371
 186
 44
 5
 Yes
Transmission (at varying percentages)   n/a 42
 7
 —
  
Total   2,078
 $1,045
 $137
 $25
  

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

21




20

Table of Contents

4.


Note 5 – Debt Obligations 


Long-term debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

First mortgage bonds due in September 2016 - 1.875%

 

$

445.0 

 

$

445.0 

Pollution control series due in January 2028 - 4.7%

 

 

35.3 

 

 

35.3 

Pollution control series due in January 2034 - 4.8%

 

 

179.1 

 

 

179.1 

Pollution control series due in September 2036 - 4.8%

 

 

100.0 

 

 

100.0 

Pollution control series due in November 2040 - rates from: 0.02% - 0.05% and 0.04% - 0.15% (a)

 

 

100.0 

 

 

100.0 

U.S. Government note due in February 2061 - 4.2%

 

 

18.1 

 

 

18.1 

Unamortized debt discount

 

 

(2.8)

 

 

(2.8)

Total long-term debt at subsidiary

 

 

874.7 

 

 

874.7 

 

 

 

 

 

 

 

Bank term loan due in May 2018 - rates from: 2.41% - 2.43% and 2.42% - 2.45% (a)

 

 

130.0 

 

 

140.0 

Senior unsecured bonds due in October 2016 - 6.5%

 

 

130.0 

 

 

130.0 

Senior unsecured bonds due in October 2019 - 6.75%

 

 

200.0 

 

 

200.0 

Senior unsecured bonds due in October 2021 - 7.25%

 

 

780.0 

 

 

780.0 

Note to DPL Capital Trust II due in September 2031 - 8.125% (b)

 

 

15.6 

 

 

15.6 

Unamortized debt discount

 

 

(0.7)

 

 

(0.7)

Total non-current portion of long-term debt

 

$

2,129.6 

 

$

2,139.6 

  September 30, December 31,
$ in millions 2015 2014
First mortgage bonds due in September 2016 - 1.875% $—
 $445.0
Pollution control series due in January 2028 - 4.7% —
 35.3
Pollution control series due in January 2034 - 4.8% —
 179.1
Pollution control series due in September 2036 - 4.8% 100.0
 100.0
Pollution control series due in November 2040 - rates from: 0.02% - 0.12% and 0.04% - 0.15% (a) —
 100.0
Pollution control series due in August 2020 - 1.13% - 1.14% 200.0
 —
U.S. Government note due in February 2061 - 4.2% 18.0
 18.1
Unamortized debt discount / premiums, net (3.5) (2.8)
Total long-term debt at subsidiary 314.5
 874.7
     
Bank term loan due in July 2020 - rates from: 2.44% - 2.45% 125.0
 —
Bank term loan due in May 2018 - rates from: 2.41% - 2.44% and 2.42% - 2.45% (a) —
 140.0
Senior unsecured bonds due in October 2016 - 6.5% 130.0
 130.0
Senior unsecured bonds due in October 2019 - 6.75% 200.0
 200.0
Senior unsecured bonds due in October 2021 - 7.25% 780.0
 780.0
Note to DPL Capital Trust II due in September 2031 - 8.125% (b) 15.6
 15.6
Unamortized debt discount / premiums, net (0.6) (0.7)
Total non-current portion of long-term debt $1,564.5
 $2,139.6

Current portion of long-term debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Bank term loan due in May 2018 - rates from: 2.41% - 2.43% and 2.42% - 2.45% (a)

 

$

30.0 

 

$

20.0 

U.S. Government note due in February 2061 - 4.2%

 

 

0.1 

 

 

0.1 

Total current portion of long-term debt

 

$

30.1 

 

$

20.1 

(a)Range of interest rates for the three months ended March 31, 2015 and the twelve months ended December 31, 2014, respectively. 

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

At March 31, 2015, maturities of long-term debt are as follows:

 

 

 

 

 

 

 

 

Due within the twelve months ending March 31,

 

 

 

($ in millions)

 

 

 

2016

 

$

30.1 

2017

 

 

615.1 

2018

 

 

40.1 

2019

 

 

50.2 

2020

 

 

200.2 

Thereafter

 

 

1,227.5 

Total maturities

 

 

2,163.2 

 

 

 

 

Unamortized premiums and discounts

 

 

(3.5)

Total long-term debt

 

$

2,159.7 
  September 30, December 31,
$ in millions 2015 2014
Bank term loan due in May 2018 - rates from: 2.41% - 2.44% and 2.42% - 2.45% (a) $—
 $20.0
U.S. Government note due in February 2061 - 4.2% 0.1
 0.1
First mortgage bonds due in September 2016 - 1.875% 445.0
 —
Unamortized debt discount (0.2) —
Total current portion of long-term debt $444.9
 $20.1


(a)Range of interest rates for the nine months ended September 30, 2015 and the twelve months ended December 31, 2014, respectively.
(b)Note payable to related party. See Note 1: Related Party Transactions for additional information.

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

22


Table of Contents

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


On July 31, 2015, DP&L refinanced its revolving credit facility, reducing the total size from $300.0 million to $175.0 million, with a $50.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million. This refinancing extended the life of the facility from May 2018 to July 2020. At March 31,September 30, 2015, there wereDP&L had drawn $10.0 million under this facility and had two letters of credit in the amount of $1.4 million outstanding under this facility, with the remaining $298.6$163.6 million available to DP&L. Fees associated with this letter of credit facility were not material during the threenine months ended March 31,September 30, 2015 or 2014.



21
Table of Contents


DP&L’s unsecured revolving credit agreement and DP&L’s amended standby letters of credit havehas two financial covenants, thecovenants. The first financial covenant measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant ratio compares EBITDA to Interest Expense ratio. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.


On July 1, 2015, the $35.3 million of DP&L's 4.7% pollution control bonds due January 2028 and $41.3 million of DP&L's 4.8% pollution control bonds due January of 2034 were called at par and were redeemed with cash.

On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bonds due November 2040 and terminated the amended standby letter of credit facilities. DP&L also called the $137.8 million of 4.8% pollution control bonds due January of 2034. These bonds were refinanced with $200.0 million of new pollution control bonds at variable rates of interest secured by first mortgage bonds in an equivalent amount, and the remaining $37.8 million was redeemed.

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

On July 31, 2015, DPL refinanced its revolving credit facility, increasing the total size from $100.0 million to $205.0 million, with a $200.0 million letter of credit sublimit and a feature that provides DPL the ability, under certain circumstances, to increase the size of the facility by an additional $95.0 million. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by DPLE secured by assets of DPLE. On October 29, 2015, DPL further secured the credit facility through a leasehold mortgage on additional assets of DPLE.  This refinancing extended the life of the facility from May 2018 to July 2020. DPL's new 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 July 31, 2020, then the maturity of this facility shall be July 15, 2016.1, 2019. At March 31,September 30, 2015, there was one letter of credit in the amount of $2.3 million outstanding under this facility, with the remaining $97.7$202.7 million available to DPL. Fees associated with this facility were not material during the threenine months ended March 31,September 30, 2015 or 2014.


Also on July 31, 2015, DPL refinanced its term loan, paying down the outstanding amount of $160.0 million using proceeds from the new term loan of $125.0 million and a combination of cash on hand and draws on short term credit facilities. The new term loan extends the term to July of 2020, pushing back required principal payments to 2017, and providing a mechanism for DPL to request additional term loans to refinance existing indebtedness. 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 DPLE secured by assets of DPLE. On October 29, 2015, DPL further secured the credit facility through a leasehold mortgage on additional assets of DPLE. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019.

DPL’s unsecured revolving credit agreement and unsecured term loan have two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant, an EBITDA to Interest Expense ratio, is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.


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




22
Table of Contents

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

5.


Note 6 – Income Taxes


The following table details the effective tax rates for the three and nine months ended March 31,September 30, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended March 31,

 

 

 

2015

 

 

2014

DPL

 

 

30.7%

 

 

(65.8)%

  Three months ended Nine months ended
  September 30, September 30,
  2015 2014 2015 2014
DPL 3.4% (71.5)% 18.6% (34.2)%

Income tax expense for the threenine months ended March 31,September 30, 2015 and 2014 was calculated using the estimated annual effective income tax rates for 2015 and 2014 of 31.1%30.8% and (65.8)(42.3)%, respectively. For the threenine months ended March 31,September 30, 2015 and March 31, 2014, management estimated the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.


For the three and nine months ended March 31,September 30, 2015, DPL’s current period effective rate was less than the estimated annual effective rate primarily due to a discrete adjustment that was recordedthe sale of MC Squared and an anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return to properly reflectinclude the filed 2013 state income tax returns.domestic manufacturing deduction. The increase in the effective rate compared to the same period in 2014 is primarily due to not having athe non-deductible goodwill impairment in 2014 which did not occur in 2015.

23


Table of Contents

6.Note 7 – Pension and Postretirement Benefits


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


We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were nowas $5.0 million and $0.0 million in employer contributions made during the threenine months ended March 31,September 30, 2015 or 2014. 

and 2014, respectively.


The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The amounts presented for postretirement include both health and life insurance. The pension and postretirement costs below have not been adjusted for amounts billed to the Service Company for former DP&L employees who are now employed by the Service Company but are still participants in the DP&L plan. See "Related Party Transactions" discussion in Note 1, "Overview"Overview and Summary of Significant Accounting Policies"Policies".


The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the three and nine months ended March 31,September 30, 2015 and 2014 was:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Periodic Benefit Cost / (Income)

 

Pension

 

Postretirement

 

 

Three months ended

 

Three months ended

 

 

March 31,

 

March 31,

$ in millions

 

2015

 

2014

 

2015

 

2014

Service cost

 

$

1.8 

 

$

1.5 

 

$

 -

 

$

0.1 

Interest cost

 

 

4.3 

 

 

4.4 

 

 

0.2 

 

 

0.2 

Expected return on plan assets

 

 

(5.7)

 

 

(5.8)

 

 

 -

 

 

(0.1)

Amortization of unrecognized:

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost

 

 

0.5 

 

 

0.4 

 

 

 -

 

 

 -

Actuarial loss / (gain)

 

 

1.5 

 

 

0.9 

 

 

(0.1)

 

 

(0.1)

Net periodic benefit cost

 

$

2.4 

 

$

1.4 

 

$

0.1 

 

$

0.1 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

$ in millions

 

Pension

 

Postretirement

 

 

 

 

 

 

 

2015

 

$

18.6 

 

$

1.4 

2016

 

 

25.2 

 

 

1.8 

2017

 

 

25.7 

 

 

1.7 

2018

 

 

26.3 

 

 

1.6 

2019

 

 

26.7 

 

 

1.5 

2020 - 2024

 

 

137.0 

 

 

6.1 
Net Periodic Benefit Cost Pension Postretirement
  Three months ended Three months ended
  September 30, September 30,
$ in millions 2015 2014 2015 2014
Service cost $1.7
 $1.5
 $0.1
 $—
Interest cost 4.4
 4.3
 0.2
 0.2
Expected return on plan assets (5.7) (5.8) (0.1) —
Amortization of unrecognized:        
Prior service cost 0.5
 0.4
 —
 —
Actuarial loss / (gain) 1.5
 0.9
 (0.1) (0.1)
Net periodic benefit cost $2.4
 $1.3
 $0.1
 $0.1

24




23

Table of Contents

7.


Net Periodic Benefit Cost Pension Postretirement
  Nine months ended Nine months ended
  September 30, September 30,
$ in millions 2015 2014 2015 2014
Service cost $5.3
 $4.5
 $0.1
 $0.1
Interest cost 13.0
 13.1
 0.5
 0.6
Expected return on plan assets (17.0) (17.2) (0.1) (0.1)
Amortization of unrecognized:        
Prior service cost 1.5
 1.1
 —
 —
Actuarial loss / (gain) 4.4
 2.6
 (0.3) (0.4)
Net periodic benefit cost $7.2
 $4.1
 $0.2
 $0.2

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions Pension Postretirement
2015 $6.2
 $0.5
2016 25.2
 1.8
2017 25.7
 1.7
2018 26.3
 1.6
2019 26.7
 1.5
2020 - 2024 137.0
 6.1

Note 8 – Fair Value Measurements


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


The following table presents the fair value and cost of our non-derivative instruments at March 31,September 30, 2015 and December 31, 2014. Information about the fair value of our derivative instruments can be found in Note 8.

9.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2015

 

December 31, 2014

$ in millions

 

Carrying Value

 

Fair Value

 

Carrying Value

 

Fair Value

Assets

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

0.1 

 

$

0.1 

 

$

0.1 

 

$

0.1 

Equity securities

 

 

2.7 

 

 

3.8 

 

 

2.7 

 

 

3.7 

Debt securities

 

 

4.6 

 

 

4.6 

 

 

4.7 

 

 

4.7 

Hedge funds

 

 

0.7 

 

 

0.7 

 

 

0.8 

 

 

0.8 

Real estate

 

 

0.3 

 

 

0.4 

 

 

0.4 

 

 

0.4 

Total Assets

 

$

8.4 

 

$

9.6 

 

$

8.7 

 

$

9.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Debt

 

$

2,159.7 

 

$

2,238.5 

 

$

2,159.7 

 

$

2,204.8 

  September 30, 2015 December 31, 2014
$ in millions Cost Fair Value Cost Fair Value
Assets        
Money market funds $0.2
 $0.2
 $0.1
 $0.1
Equity securities 2.7
 3.4
 2.7
 3.7
Debt securities 4.5
 4.4
 4.7
 4.7
Hedge funds 0.7
 0.7
 0.8
 0.8
Real estate 0.3
 0.3
 0.4
 0.4
Total Assets $8.4
 $9.0
 $8.7
 $9.7
Liabilities        
Debt $2,009.4
 $2,033.7
 $2,159.7
 $2,204.8

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


Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value,cost, net of unamortized premium or discount in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 to 2061.




24
Table of Contents

Master Trust Assets

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


DPLhad $1.0$0.5 million ($0.70.4 million after tax) of unrealized gains and $0.1 million ($0.1 million after tax) of unrealized losses on the Master Trust assets in AOCI at September 30, 2015 and $0.8 million ($0.5 million after tax) of unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 2015 and $0.8 million ($0.5 million after tax) of unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.


During the threenine months ended March 31,September 30, 2015, $0.6$1.0 million ($0.40.7 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings as investments are sold over the next twelve months to facilitate the distribution of benefits.


Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:

·

Level 1 (quoted prices in active markets for identical assets or liabilities);

·

Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active)Level 1 (quoted prices in active markets for identical assets or liabilities);

·

Level 3 (unobservable inputs). 

Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active);

25

Level 3 (unobservable inputs).

Table of Contents


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


We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the three months and nine months ended MarchSeptember 30, 2015 and 2014.




25
Table of Contents

The fair value of assets and liabilities at March 31,September 30, 2015 and December 31, 2014 and the respective category within the fair value hierarchy for DPL was determined as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets and Liabilities at Fair Value

 

 

 

 

Level 1

 

Level 2

 

Level 3

$ in millions

 

Fair Value at March 31, 2015

 

Based on Quoted Prices in Active Markets

 

Other Observable Inputs

 

Unobservable Inputs

Assets

 

 

 

 

 

 

 

 

 

 

 

 

Master Trust assets

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

0.1 

 

$

0.1 

 

$

 -

 

$

 -

Equity securities

 

 

3.8 

 

 

 -

 

 

3.8 

 

 

 -

Debt securities

 

 

4.6 

 

 

 -

 

 

4.6 

 

 

 -

Hedge funds

 

 

0.7 

 

 

 -

 

 

0.7 

 

 

 -

Real estate

 

 

0.4 

 

 

 -

 

 

0.4 

 

 

 -

Total Master Trust assets

 

 

9.6 

 

 

0.1 

 

 

9.5 

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Assets

 

 

 

 

 

 

 

 

 

 

 

 

  FTRs

 

 

0.3 

 

 

 -

 

 

 -

 

 

0.3 

Forward power contracts

 

 

20.3 

 

 

 -

 

 

18.8 

 

 

1.5 

Total Derivative assets

 

 

20.6 

 

 

 -

 

 

18.8 

 

 

1.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$

30.2 

 

$

0.1 

 

$

28.3 

 

$

1.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Heating oil

 

 

0.3 

 

 

0.3 

 

 

 -

 

 

 -

Forward power contracts

 

 

20.4 

 

 

 -

 

 

19.0 

 

 

1.4 

Total Derivative liabilities

 

 

20.7 

 

 

0.3 

 

 

19.0 

 

 

1.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

 

2,238.5 

 

 

 -

 

 

2,220.3 

 

 

18.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities

 

$

2,259.2 

 

$

0.3 

 

$

2,239.3 

 

$

19.6 

Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair value at September 30, 2015 Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs
Assets        
Master Trust assets        
Money market funds $0.2
 $0.2
 $—
 $—
Equity securities 3.4
 —
 3.4
 —
Debt securities 4.4
 —
 4.4
 —
Hedge funds 0.7
 —
 0.7
 —
Real estate 0.3
 —
 0.3
 —
Total Master Trust assets 9.0
 0.2
 8.8
 —
Derivative Assets        
FTRs 0.4
 —
 —
 0.4
Forward power contracts 30.0
 —
 30.0
 —
Total Derivative assets 30.4
 —
 30.0
 0.4
Total Assets $39.4
 $0.2
 $38.8
 $0.4
Liabilities        
Derivative Liabilities        
 FTRs 0.7
 —
 —
 0.7
Forward power contracts 24.4
 —
 22.2
 2.2
Total Derivative liabilities 25.1
 —
 22.2
 2.9
Debt 2,033.7
 —
 2,015.6
 18.1
Total Liabilities $2,058.8
 $—
 $2,037.8
 $21.0



26

Table of Contents


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets and Liabilities at Fair Value

 

 

 

 

Level 1

 

Level 2

 

Level 3

$ in millions

 

Fair Value at December 31, 2014

 

Based on Quoted Prices in Active Markets

 

Other Observable Inputs

 

Unobservable Inputs

Assets

 

 

 

 

 

 

 

 

 

 

 

 

Master Trust assets

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

0.1 

 

$

0.1 

 

$

 -

 

$

 -

Equity securities

 

 

3.7 

 

 

 -

 

 

3.7 

 

 

 -

Debt securities

 

 

4.7 

 

 

 -

 

 

4.7 

 

 

 -

Hedge funds

 

 

0.8 

 

 

 -

 

 

0.8 

 

 

 -

Real estate

 

 

0.4 

 

 

 -

 

 

0.4 

 

 

 -

Total Master Trust assets

 

 

9.7 

 

 

0.1 

 

 

9.6 

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

Forward power contracts

 

 

14.9 

 

 

 -

 

 

13.7 

 

 

1.2 

Total Derivative assets

 

 

14.9 

 

 

 -

 

 

13.7 

 

 

1.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$

24.6 

 

$

0.1 

 

$

23.3 

 

$

1.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

FTRs

 

$

0.6 

 

$

 -

 

$

 -

 

$

0.6 

Heating oil futures

 

 

0.4 

 

 

0.4 

 

 

 -

 

 

 -

Natural gas futures

 

 

0.1 

 

 

0.1 

 

 

 -

 

 

 -

Forward power contracts

 

 

11.1 

 

 

 -

 

 

11.1 

 

 

 -

Total Derivative liabilities

 

 

12.2 

 

 

0.5 

 

 

11.1 

 

 

0.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

 

2,204.8 

 

 

 -

 

 

2,186.6 

 

 

18.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities

 

$

2,217.0 

 

$

0.5 

 

$

2,197.7 

 

$

18.8 

Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair value at December 31, 2014 Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs
Assets        
Master Trust assets        
Money market funds $0.1
 $0.1
 $—
 $—
Equity securities 3.7
 —
 3.7
 —
Debt securities 4.7
 —
 4.7
 —
Hedge funds 0.8
 —
 0.8
 —
Real estate 0.4
 —
 0.4
 —
Total Master Trust assets 9.7
 0.1
 9.6
 —
Derivative assets        
Forward power contracts 14.9
 —
 13.7
 1.2
Total Derivative assets 14.9
 —
 13.7
 1.2
         
Total Assets $24.6
 $0.1
 $23.3
 $1.2
         
Liabilities        
Derivative liabilities        
FTRs $0.6
 $—
 $—
 0.6
Heating oil futures 0.4
 0.4
 —
 —
Natural gas futures 0.1
 0.1
 —
 —
Forward power contracts 11.1
 —
 11.1
 —
Total Derivative liabilities 12.2
 0.5
 11.1
 0.6
         
Debt 2,204.8
 —
 2,186.6
 18.2
         
Total Liabilities $2,217.0
 $0.5
 $2,197.7
 $18.8

Our financial instruments are valued using the market approach in the following categories:

·

Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents.  The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.

·

Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market).  Other Level 2 assets include open-ended mutual funds that are in the Master Trust, which are valued using observable prices based on the end of day NAV per unit.

Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.

·

Level 3 inputs such as financial transmission rights 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.

Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include open-ended mutual funds that are in the Master Trust, which are valued using observable prices based on 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 98%97% of the inputs to the fair value of our derivative instruments are from quoted market prices.


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

27


Table of Contents

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


27
Table of Contents

approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for ash ponds, asbestos, river structures and underground storage tanks increased by $0.6a net amount of $38.7 million and $1.2 million during the threenine months ended March 31,September 30, 2015 and 2014, respectively.

The majority of the increase in 2015 is due to an increase in the AROs for ash ponds ($40.6 million) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015.


When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes Goodwill and Long-lived assets measured at fair value on a nonrecurringnon-recurring basis during the period and their level within the fair value hierarchy (there were no impairments during the quarternine months ended March 31,September 30, 2015):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Three months ended March 31, 2014

 

 

 

 

Carrying

 

Fair Value

 

 

 

Gross

 

 

 

Amount (c)

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Loss

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-lived assets (a)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L (East Bend)

 

$

14.2 

 

$

 -

 

$

 -

 

$

2.7 

 

$

11.5 

Goodwill (b)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPLER Reporting unit

 

$

135.8 

 

$

 -

 

$

 -

 

$

 -

 

$

135.8 

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

(a)See Note 9 for further information
(b)See Note 12 for further information

(b)See Note 11 for further information

(c)Carrying amount at date of valuation

8.


Note 9 – Derivative Instruments and Hedging Activities


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


At March 31,September 30, 2015, DPL had the following outstanding derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Accounting Treatment

 

Unit

 

Purchases
(in thousands)

 

Sales
(in thousands)

 

Net Purchases/ (Sales)
(in thousands)

FTRs

 

 

Mark to Market

 

MWh

 

 

4.2 

 

 

 -

 

 

4.2 

Heating oil futures

 

 

Mark to Market

 

Gallons

 

 

252.0 

 

 

 -

 

 

252.0 

Forward power contracts

 

 

Cash Flow Hedge

 

MWh

 

 

843.5 

 

 

(3,708.3)

 

 

(2,864.8)

Forward power contracts

 

 

Mark to Market

 

MWh

 

 

1,565.1 

 

 

(4,826.9)

 

 

(3,261.8)

28

Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Mark to Market MWh 24.7
 —
 24.7
Forward power contracts Cash Flow Hedge MWh 1,361.2
 (7,857.7) (6,496.5)
Forward power contracts Mark to Market MWh 5,309.7
 (1,850.3) 3,459.4

Table of Contents


At December 31, 2014, DPL had the following outstanding derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Accounting Treatment

 

Unit

 

Purchases
(in thousands)

 

Sales
(in thousands)

 

Net Purchases/ (Sales)
(in thousands)

FTRs

 

 

Mark to Market

 

MWh

 

 

10.5 

 

 

 -

 

 

10.5 

Heating oil futures

 

 

Mark to Market

 

Gallons

 

 

378.0 

 

 

 -

 

 

378.0 

Natural gas futures

 

 

Mark to Market

 

Dths

 

 

200.0 

 

 

 -

 

 

200.0 

Forward power contracts

 

 

Cash Flow Hedge

 

MWh

 

 

175.0 

 

 

(2,991.0)

 

 

(2,816.0)

Forward power contracts

 

 

Mark to Market

 

MWh

 

 

1,725.2 

 

 

(2,707.8)

 

 

(982.6)

Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Mark to Market MWh 10.5
 —
 10.5
Heating oil futures Mark to Market Gallons 378.0
 —
 378.0
Natural gas futures Mark to Market Dths 200.0
 —
 200.0
Forward power contracts Cash Flow Hedge MWh 175.0
 (2,991.0) (2,816.0)
Forward power contracts Mark to Market MWh 1,725.2
 (2,707.8) (982.6)



28
Table of Contents

Cash Flow Hedges

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


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

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

29


Table of Contents

The following tables providetable provides information for DPLconcerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31,September 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Three months ended

 

 

March 31, 2015

 

March 31, 2014

 

 

 

 

Interest

 

 

 

Interest

$ in millions (net of tax)

 

Power

 

Rate Hedge

 

Power

 

Rate Hedge

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning accumulated derivative gain in AOCI

 

$

0.2 

 

$

18.3 

 

$

1.4 

 

$

19.2 

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

 

 

0.1 

 

 

 -

 

 

(12.9)

 

 

 -

Net gains / (losses) reclassified to earnings

Interest expense

 

 

 -

 

 

(0.1)

 

 

 -

 

 

(0.3)

Revenues

 

 

(0.2)

 

 

 -

 

 

6.5 

 

 

 -

Purchased power

 

 

0.9 

 

 

 -

 

 

(0.7)

 

 

 -

Ending accumulated derivative gain / (loss) in AOCI

 

$

1.0 

 

$

18.2 

 

$

(5.7)

 

$

18.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

Portion expected to be reclassified to earnings in the next twelve months (a)

 

$

1.1 

 

$

0.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

21 

 

 

0 

 

 

 

 

 

 

  Three months ended Three months ended
  September 30, 2015 September 30, 2014
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI $1.1
 $17.8
 $(12.4) $18.8
Net gains / (losses) associated with current period hedging transactions 7.8
 —
 1.2
 —
Net gains / (losses) reclassified to earnings      
Interest expense —
 (0.1) —
 (0.2)
Revenues (2.5) —
 3.4
 —
Purchased power 0.6
 —
 0.2
 —
Ending accumulated derivative gain / (loss) in AOCI $7.0
 $17.7
 $(7.6) $18.6

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the nine months ended September 30, 2015 and 2014:
  Nine months ended Nine months ended
  September 30, 2015 September 30, 2014
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gain in AOCI $0.2
 $18.3
 $1.4
 $19.2
Net gains / (losses) associated with current period hedging transactions 9.6
 —
 (23.8) —
Net gains / (losses) reclassified to earnings      
Interest expense —
 (0.6) —
 (0.6)
Revenues (4.5) —
 15.4
 —
Purchased power 1.7
 —
 (0.6) —
Ending accumulated derivative gain / (loss) in AOCI $7.0
 $17.7
 $(7.6) $18.6
Portion expected to be reclassified to earnings in the next twelve months (a)
 $3.3
 $(0.8)    
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 39
 0
    

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



29
Table of Contents


Mark to Market Accounting

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


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


Regulatory Assets and Liabilities

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

30


Table of Contents

The following tables present the amount and classification within the Condensed Consolidated Statements of Operations or Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and nine months ended March 31,September 30, 2015 and 2014. 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Heating Oil

 

FTRs

 

Power

 

Natural Gas

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized gain / (loss)

 

$

0.1 

 

$

0.9 

 

$

(2.9)

 

$

0.1 

 

$

(1.8)

Realized loss

 

 

(0.1)

 

 

(0.1)

 

 

(2.3)

 

 

(0.1)

 

 

(2.6)

Total

 

$

 -

 

$

0.8 

 

$

(5.2)

 

$

 -

 

$

(4.4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Recorded in Income Statement: gain / (loss)

 

 

 

Purchased power

 

 

 -

 

 

0.8 

 

 

(4.9)

 

 

 -

 

 

(4.1)

Revenue

 

 

 -

 

 

 -

 

 

(0.3)

 

 

 -

 

 

(0.3)

Total

 

$

 -

 

$

0.8 

 

$

(5.2)

 

$

 -

 

$

(4.4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended March 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended September 30, 2015For the three months ended September 30, 2015

$ in millions

 

Heating Oil

 

FTRs

 

Power

 

Total

 Heating Oil FTRs Power Total

 

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized loss

 

$

(0.1)

 

$

(0.3)

 

$

(5.5)

 

$

(5.9)

Realized gain / (loss)

 

 

0.1 

 

 

 -

 

 

(2.0)

 

 

(1.9)
Change in unrealized gain / (loss) $0.1
 $0.1
 $(3.2) $(3.0)
Realized loss (0.2) (0.1) (4.3) (4.6)

Total

 

$

 -

 

$

(0.3)

 

$

(7.5)

 

$

(7.8)		 $(0.1) $—
 $(7.5) $(7.6)

 

 

 

 

 

 

 

 

 

 

 

 

Recorded in Income Statement: loss

Recorded in Income Statement: gain / (loss)Recorded in Income Statement: gain / (loss)  

Purchased power

 

 

 -

 

 

(0.3)

 

 

(7.5)

 

 

(7.8)		 $—
 $—
 $(11.0) $(11.0)
Revenue —
 —
 3.5
 3.5

Fuel

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 (0.1) —
 —
 (0.1)

Total

 

$

 -

 

$

(0.3)

 

$

(7.5)

 

$

(7.8)		 $(0.1) $—
 $(7.5) $(7.6)


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



30
Table of Contents

For the nine months ended September 30, 2015
$ in millions Heating Oil FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $0.4
 $0.2
 $(4.9) $0.1
 $(4.2)
Realized loss (0.3) (0.1) (8.1) (0.1) (8.6)
Total $0.1
 $0.1
 $(13.0) $—
 $(12.8)
Recorded on Balance Sheet: gain/ (loss)  
Regulatory Asset $0.1
 $—
 $—
 $—
 $0.1
Recorded in Income Statement: gain / (loss)  
Purchased power —
 0.1
 (21.9) —
 (21.8)
Revenue —
 —
 8.9
 —
 8.9
Total $0.1
 $0.1
 $(13.0) $—
 $(12.8)

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

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.



31

Table of Contents


The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.

The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at September 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Values of Derivative Instruments

at March 31, 2015

 

 

 

 

 

 

 

 

Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets

 

 

 

$ in millions

 

Hedging Designation

 

Gross Fair Value as presented in the Condensed Consolidated Balance Sheets

 

Financial Instruments with Same Counterparty in Offsetting Position

 

Cash Collateral

 

 

Net Balance Fair Value

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current assets)

 

Forward power contracts

 

Cash Flow

 

$

5.2 

 

$

(2.5)

 

$

 -

 

$

2.7 

Forward power contracts

 

MTM

 

 

4.9 

 

 

(3.2)

 

 

 -

 

 

1.7 

FTRs

 

MTM

 

 

0.3 

 

 

 -

 

 

 -

 

 

0.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred assets)

Forward power contracts

 

Cash Flow

 

 

3.8 

 

 

(2.7)

 

 

 -

 

 

1.1 

Forward power contracts

 

MTM

 

 

6.4 

 

 

(0.6)

 

 

 -

 

 

5.8 

Total assets

 

 

 

 

$

20.6 

 

$

(9.0)

 

$

 -

 

$

11.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current liabilities)

Forward power contracts

 

Cash Flow

 

$

4.1 

 

$

(2.5)

 

$

(1.6)

 

$

 -

Forward power contracts

 

MTM

 

 

13.0 

 

 

(3.2)

 

 

(8.8)

 

 

1.0 

Heating oil

 

MTM

 

 

0.3 

 

 

 -

 

 

(0.3)

 

 

 -

FTRs

 

MTM

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred liabilities)

Forward power contracts

 

Cash Flow

 

 

2.7 

 

 

(2.7)

 

 

 -

 

 

 -

Forward power contracts

 

MTM

 

 

0.6 

 

 

(0.6)

 

 

 -

 

 

 -

Total liabilities

 

 

 

 

$

20.7 

 

$

(9.0)

 

$

(10.7)

 

$

1.0 

Fair Values of Derivative Instruments
at September 30, 2015
      Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets  
$ in millions Hedging Designation Gross Fair Value as presented in the Condensed Consolidated Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Balance Fair Value
Assets          
Short-term derivative positions (presented in Other current assets)  
Forward power contracts Cash Flow $10.8
 $(6.0) $—
 $4.8
Forward power contracts MTM 5.3
 (4.0) —
 1.3
FTRs MTM 0.4
 (0.4) —
 —
           
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts Cash Flow 8.2
 (3.0) —
 5.2
Forward power contracts MTM 5.7
 (5.2) —
 0.5
Total assets   $30.4
 $(18.6) $—
 $11.8
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts Cash Flow $6.0
 $(6.0) $—
 $—
Forward power contracts MTM 8.9
 (4.0) (4.6) 0.3
FTRs MTM 0.7
 (0.4) —
 0.3
           
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts Cash Flow 3.0
 (3.0) —
 —
Forward power contracts MTM 6.5
 (5.2) (1.0) 0.3
Total liabilities   $25.1
 $(18.6) $(5.6) $0.9




32

Table of Contents


The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Values of Derivative Instruments

at December 31, 2014

 

 

 

 

 

 

 

 

Gross Amounts Not Offset in the Condensed Consolidated Balance Sheets

 

 

 

$ in millions

 

Hedging Designation

 

Gross Fair Value as presented in the Condensed Consolidated Balance Sheets

 

Financial Instruments with Same Counterparty in Offsetting Position

 

Cash Collateral

 

 

Net Balance Fair Value

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current assets)

 

 

 

 

 

 

 

 

 

Forward power contracts

 

Cash Flow

 

$

5.6 

 

$

(2.0)

 

$

 -

 

$

3.6 

Forward power contracts

 

MTM

 

 

5.5 

 

 

(3.4)

 

 

 -

 

 

2.1 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred assets)

 

 

 

 

 

 

 

 

 

Forward power contracts

 

Cash Flow

 

 

0.3 

 

 

(0.3)

 

 

 -

 

 

 -

Forward power contracts

 

MTM

 

 

3.5 

 

 

(0.9)

 

 

 -

 

 

2.6 

Total assets

 

 

 

 

$

14.9 

 

$

(6.6)

 

$

 -

 

$

8.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current liabilities)

 

 

 

 

 

 

Forward power contracts

 

Cash Flow

 

$

2.1 

 

$

(2.0)

 

$

 -

 

$

0.1 

Forward power contracts

 

MTM

 

 

7.5 

 

 

(3.4)

 

 

(4.1)

 

 

 -

FTRs

 

MTM

 

 

0.6 

 

 

 -

 

 

 -

 

 

0.6 

Heating oil futures

 

MTM

 

 

0.4 

 

 

 -

 

 

(0.4)

 

 

 -

Natural gas

 

MTM

 

 

0.1 

 

 

 -

 

 

(0.1)

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred liabilities)

 

 

 

 

 

 

Forward power contracts

 

Cash Flow

 

 

0.6 

 

 

(0.3)

 

 

(0.3)

 

 

 -

Forward power contracts

 

MTM

 

 

0.9 

 

 

(0.9)

 

 

 -

 

 

 -

Total liabilities

 

 

 

 

$

12.2 

 

$

(6.6)

 

$

(4.9)

 

$

0.7 

Fair Values of Derivative Instruments
at December 31, 2014
      
Gross Amounts Not Offset in the Condensed Consolidated
Balance Sheets
  
$ in millions Hedging Designation Gross Fair Value as presented in the Condensed Consolidated Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Balance Fair Value
Assets          
Short-term derivative positions (presented in Other current assets)      
Forward power contracts Cash Flow $5.6
 $(2.0) $—
 $3.6
Forward power contracts MTM 5.5
 (3.4) —
 2.1
           
Long-term derivative positions (presented in Other deferred assets)  
  
  
Forward power contracts Cash Flow 0.3
 (0.3) —
 —
Forward power contracts MTM 3.5
 (0.9) —
 2.6
Total assets   $14.9
 $(6.6) $—
 $8.3
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)    
Forward power contracts Cash Flow $2.1
 $(2.0) $—
 $0.1
Forward power contracts MTM 7.5
 (3.4) (4.1) —
FTRs MTM 0.6
 —
 —
 0.6
Heating oil futures MTM 0.4
 —
 (0.4) —
Natural gas MTM 0.1
 —
 (0.1) —
           
Long-term derivative positions (presented in Other deferred liabilities)  
  
Forward power contracts Cash Flow 0.6
 (0.3) (0.3) —
Forward power contracts MTM 0.9
 (0.9) —
 —
Total liabilities   $12.2
 $(6.6) $(4.9) $0.7

The aggregate fair value of DPL’s commodity derivative instruments that were in a MTM loss position at March 31,September 30, 2015 was $20.7 $25.1 million. $10.7$5.6 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 $9.0$18.6 million. Since our debt is below investment grade, we could have to post collateral for the remaining $1.0$0.9 million.

9.


Note 10 – Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. –


Guarantees

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

33


Table of Contents

At March 31,September 30, 2015, DPL had $20.5$19.3 million of guarantees to third parties for future financial or performance assurance under such agreements: $2.0 million of guarantees on behalf of DPLER $18.3and $17.3 million of guarantees on behalf of DPLE and $0.2 million of guarantees on behalf of MC Squared, which will be released upon the April 1, 2015 sale of MC Squared.DPLE. The guarantee arrangements entered into byDPL with these third parties cover select present


33
Table of Contents

and future obligations of DPLE DPLER and MC SquaredDPLER to such beneficiaries and are terminable by DPL upon written notice to the beneficiaries within a certain time. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was $2.2$1.1 million at March 31,September 30, 2015.


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


DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP. As of March 31,September 30, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.4$73.9 million, of a $1,519.3$1,507.9 million debt obligation that has maturities from 2018 to 2040. This would only happen if OVEC defaulted on its debt payments. As of March 31,September 30, 2015, 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, 2014.


Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under various laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31,September 30, 2015, cannot be reasonably determined.


Environmental Matters

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

·

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

·

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


·

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

The federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions,

·

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

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 climate change,

·

Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

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

·

Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste.  The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products. 

34

TableRules and future rules issued by the USEPA, the Ohio EPA or other authorities that require reporting and reductions of Contents

GHGs,

Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP.


34
Table of Contents

At March 31,September 30, 2015, and December 31, 2014, we had accruals of approximately $0.8$0.7 million and $0.8 million, respectively, for environmental matters and other claims. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated, which are disclosed in the paragraphs below. We evaluate the potential liability related to environmental matters quarterly and may revise our accruals. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.


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

such EGUs and stations or our financial condition.


National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO2 replacing the previous 24-hour standard and annual standard with a one-hour standard.  Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations designated as non-attainment.  Beckjord Unit 6 was retired effective October 1, 2014. Non-attainment areas will be required to meet the 2010 standard by October 2018. On April 17, 2014,August 21, 2015, the USEPA proposedfinalized a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO2 emissions.emissions, which became effective on September 21, 2015. The rule if finalized,directs state agencies to provide data to characterize air quality in areas with sources of SO2 above 2,000 tons per year to identify maximum 1-hour concentrations of SO2 in ambient air. The rule could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations. On March 20, 2015, the USEPA informed environmental commissioners of 28 states, including Ohio, that certain areas within their states will be addressed in the next round of designations.  The areas will be included if they have monitors that have newly violated the standard, or have areas with a stationary source that had SO2 emissions greater than a specified level.  The designations are to be completed by July 2, 2016.  DP&L’s co-owned unit Zimmer meets the criteria for stationary sources. DP&L is unable to determine the effect of thesethe rule changes on its operations.

Carbon Dioxide


On October 1, 2015, the USEPA released a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. We are currently reviewing the rule and Other Greenhouse Gas Emissions

assessing the impact on our operations. We cannot at this time determine the impact of this rule, but it could be material.


Climate Change Legislation and Regulation
The USEPA issued proposed GHG emissionsOn October 23, 2015, the USEPA's final CO2 emission rules for existing power plants (called the Clean Power Plan) were published in the Federal Register with an effective date of December 22, 2015. Additionally, the final NSPS for CO2 emissions from new, modified and reconstructed generating unitsfossil-fuel-fired power plants were published in the Federal Register on June 2, 2014.  UnderOctober 23, 2015 and are effective immediately. The Clean Power Plan provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved by 2030. Prior to the proposed rules, calledrule's publication in the Federal Register, fifteen states, including Ohio, filed a petition in the U.S. Court of Appeals for the D.C. Circuit seeking a stay of the Clean Power Plan, which was denied by the Court in September 2015. On October 23, 2015, several states would be judged against state-specific CO2 emissions targets beginningand industry groups filed petitions in 2020, with an expected total U.S. power sector emissions reductionthe D.C. Circuit Court of 30% from 2005 levels by 2030.  For Ohio specifically,Appeals challenging the Clean Power Plan proposes an interim goalas published in the Federal Register, including a twenty-four state consortium that includes Ohio. The D.C. Circuit Court has issued orders consolidating the current pending challenges to the CPP under the lead case, West Virginia v. EPA. On October 23, 2015, North Dakota filed a petition for 2020-2029review of the GHG NSPS in the D.C. Circuit Court, and a proposed 2030 final goalcoalition of 1,452 poundsenvironmental groups have moved to intervene on behalf of CO2 per megawatt hourEPA in both the CPP and 1,338 poundsNSPS litigation. These state petitioners, as well as industry groups separately challenging the rule, have filed motions with the D.C. Circuit Court requesting a stay of CO2 per megawatt hour, respectively,the rule. The D.C. Circuit Court has issued orders consolidating the current pending challenges to the Clean Power Plan under the lead case, West Virginia v. USEPA. On October 23, 2015, North Dakota filed a reductionpetition for review of approximately 28% from 2012 levels.  The proposed rule requires states to submit implementation plans to meet the standards set forthCO2 NSPS in the D.C. Circuit Court, and a coalition of environmental groups have moved to intervene on behalf of USEPA in both the Clean Power Plan and NSPS litigation. Additional legal challenges are expected. We are currently reviewing the rule by June 30, 2016, withand assessing the possibilityimpact on our operations. Our business, financial condition or results of one- or two-year extensions under certain circumstances.  The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures.  Weoperations could be required, among other things, to make efficiency improvements at our facilities.  USEPA expects to finalizematerially and adversely affected by this rule by August 1, 2015.  We cannot predict the effect of these proposed rules on rule.DP&L’s operations. 


Clean Water Act – Regulation of Water Discharge

In December 2006, DP&Lsubmitted a renewal application for the Stuart generating station NPDES permit that was due to expire on June 30, 2007. The Ohio EPA issued a draft permit that was received onin November 12, 2008. In September 2010, the USEPA formally objected to the November 12, 2008, draft permit due to questions regarding the basis for the alternate thermal limitation. The Ohio EPA issued a draft permit in December 2011 and a public hearing was held onin February 2, 2012. The draft permit required DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&Lsubmitted comments to the draft permit. In November 2012, the Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L


35
Table of Contents

submitted comments. In December 2012, the USEPA formally withdrew their objection to the permit. On January 7, 2013, the Ohio EPA issued a final permit.

35


Table of Contents

On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission. A hearing before the Commission is scheduledhas been rescheduled for August 2015.March 2016. Depending on the outcome of the appeal process, the effects on DP&L’s business, financial condition or results of operations could be material.


On September 30, 2015, the USEPA released its final rule regulating various wastewater streams from steam electric power plants. The regulations were published in the Federal Register on November 3, 2015. We are reviewing the the rule to assess the potential impact on our operations and our current or future NPDES permits.

Regulation of Waste Disposal

In September 2002, DP&Land other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. On August 16, 2006, an Administrative Settlement Agreement and Order on Consent (“ASAOC”) for the site was executed and became effective among a group of PRPs, not including DP&L, and the USEPA. On August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio (the “District Court”) against DP&L and numerous other defendants alleging that DP&Land the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. On February 10, 2011, the District Court Judge dismissed claims against DP&Lthat related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The District Court Judge, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck directly to the landfill. Discovery, including depositions of past and present DP&Lemployees, was conducted in 2012. On February 8, 2013, the District Court Judge granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by the PRP group in performing an RI/FS under the August 15, 2006 ASAOC. That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th6th Circuit affirmed the lower Court’s ruling and subsequently denied a request by the plaintiffsPRP group for rehearing. On November 14, 2014, the PRP group appealed the decision to the U.S. Supreme Court, but the writ of certiorari was denied by the Court on January 20, 2015. On April 5, 2013, the PRP group entered into a second ASAOC (the "2013 ASAOC") relating primarily to vapor intrusion from under some of the buildings at the South Dayton Dump landfill site. On April 13, 2013, as amended July 30, 2013, the PRP group filed another civil complaint against DP&L and numerous other defendants alleging that each defendant contributed to the contamination of the site by delivering hazardous waste to the site or by releasing hazardous waste on other sites that migrated to the landfill site. On February 18, 2014, after considering various motions and alternative grounds to dismiss, the District Court Judge dismissed some of the alleged grounds for relief that the PRP group had made, but ruled in the PRP group’s favor with respect to motions to dismiss the case in its entirety finding, among other things, that the 2013 ASAOC involved a different scope of work and thus the contributions sought were not seeking the same remedy that had been dismissed in the first civil suit. Appeals fromof this ruling are pending before the 6th6th Circuit Court of Appeals. On January 14, 2015, the PRP group served DP&L and other defendants a request for production of documents related to any survey regarding waste management or waste disposal.disposal surveys. Information responsive to this request was provided on February 17, 2015. In addition, on January 16, 2015, the USEPA issued a Special Notice Letter and Section 104(e) Information Request to DP&L and other defendants, requesting historical information related to waste management practices.practices that may be relevant to the site. DP&L responded to this request on March 27, 2015. In June 2015, DP&L was again requested to grant access to the DP&L service building property for the purpose of collecting groundwater samples from selected monitoring wells. DP&L granted access and groundwater sampling took place in June 2015. As a result of an August 11, 2015 meeting among the parties, the parties have agreed to stay the case in order to explore the possibility of a negotiated resolution of some or all of the issues.  DP&L is unable to predict the outcome of this actionthese actions by the plaintiffs and USEPA. Additionally, the District Court’s 2013 ruling and the Court of Appeals’


36
Table of Contents

affirmation of that ruling in 2014 does not address future litigation that may arise with respect to actual remediation costs. While DP&L is unable to predict the outcome of these and any future matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its business, financial condition or results of operations.


Regulation of Ash Ponds

There has been increasing advocacy to regulate coal combustion residuals (CCR) under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle

36

Table of Contents

D. The USEPA released its final rule onin December 19, 2014, designating coal combustion residuals that are not beneficially reused as non-hazardous solid waste under RCRA Subtitle D. The rule was published in the Federal Register onin April 17, 2015 and becomesbecame effective October 19, 2015, and applies new detailed management practices to new and existing landfills and surface impoundments, including lateral expansions of such units. DP&L is currently reviewingBased on our review of the rule, and assessingwe have adjusted our AROs related to ash ponds (see Note 8), but we are currently unable to determine the full impact on our operations.  Our business, financial condition or operations could be materially and adversely affectedof the rule as it is contingent upon future activities required by thisthe regulation.

10.


Note 11 – Business Segments


DPL operates through two segments; Utility and Competitive Retail. The Utility segment consists of the operations of DPL’s subsidiary, DP&L. The Competitive Retail segment consists of DPL’swholly owned subsidiary DPLER, includingwhich included, prior to its sale, DPLER’s wholly owned subsidiary, MC Squared. MC Squared was sold effective April 1, 2015. This is how we view our business and make decisions on how to allocate resources and evaluate performance.


The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and selldeliver electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired power plants and DP&L distributes power to more than 516,000515,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and to other Ohio utilities and any excess energy and capacity is sold into the PJM wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.


The Competitive Retail segment is comprised of the DPLER and, prior to its sale, MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. As of March 31,September 30, 2015, the Competitive Retail segment sold electricity to approximately 259,000128,000 customers located throughout Ohio and in Illinois.  This number includes approximately 116,000 customers in Northern Illinois of MC Squared, a Chicago-based retail electricity supplier.Ohio. On April 1, 2015, DPLER closed on the sale of MC Squared to Chicago-based Wolverine.  After considering the sale of MC Squared on April 1, 2015, the Competitive Retail segment sold electricity to 143,000 customers.Squared. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. The majority of intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.


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


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




37

Table of Contents


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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Utility

 

Competitive Retail

 

Other

 

Adjustments and Eliminations

 

DPL Consolidated

For the three months ended March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

350.6 

 

$

122.3 

 

$

21.6 

 

$

 -

 

$

494.5 

Intersegment revenues

 

 

110.7 

 

 

 -

 

 

1.6 

 

 

(112.3)

 

 

 -

Total revenues

 

 

461.3 

 

 

122.3 

 

 

23.2 

 

 

(112.3)

 

 

494.5 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel

 

 

69.3 

 

 

 -

 

 

7.1 

 

 

 -

 

 

76.4 

Purchased power

 

 

189.7 

 

 

111.7 

 

 

4.2 

 

 

(111.4)

 

 

194.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross margin

 

$

202.3 

 

$

10.6 

 

$

11.9 

 

$

(0.9)

 

$

223.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

$

34.7 

 

$

0.3 

 

$

 -

 

$

 -

 

$

35.0 

Interest expense

 

 

8.7 

 

 

 -

 

 

21.9 

 

 

(0.1)

 

 

30.5 

Income tax expense (benefit)

 

 

14.8 

 

 

1.3 

 

 

(3.4)

 

 

 -

 

 

12.7 

Net income / (loss)

 

 

36.5 

 

 

1.6 

 

 

(9.4)

 

 

 -

 

 

28.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash capital expenditures

 

$

33.1 

 

$

0.2 

 

$

0.4 

 

$

 -

 

$

33.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

3,289.7 

 

$

72.3 

 

$

1,476.1 

 

$

(1,284.2)

 

$

3,553.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Utility

 

Competitive Retail

 

Other

 

Adjustments and Eliminations

 

DPL Consolidated

For the three months ended March 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

292.6 

 

$

148.4 

 

$

19.2 

 

$

0.1 

 

$

460.3 

Intersegment revenues

 

 

139.5 

��

 

 -

 

 

1.0 

 

 

(140.5)

 

 

 -

Total revenues

 

 

432.1 

 

 

148.4 

 

 

20.2 

 

 

(140.4)

 

 

460.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel

 

 

84.3 

 

 

 -

 

 

5.7 

 

 

 -

 

 

90.0 

Purchased power

 

 

168.0 

 

 

140.2 

 

 

5.4 

 

 

(139.5)

 

 

174.1 

Amortization of intangibles

 

 

 -

 

 

 -

 

 

0.3 

 

 

 -

 

 

0.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross margin

 

$

179.8 

 

$

8.2 

 

$

8.8 

 

$

(0.9)

 

$

195.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

$

36.5 

 

$

0.1 

 

$

(1.4)

 

$

0.1 

 

$

35.3 

Goodwill impairment

 

 

 -

 

 

 -

 

 

135.8 

 

 

 -

 

 

135.8 

Fixed-asset impairment

 

 

 -

 

 

 -

 

 

11.5 

 

 

 -

 

 

11.5 

Interest expense

 

 

7.8 

 

 

0.1 

 

 

23.1 

 

 

(0.2)

 

 

30.8 

Income tax expense (benefit)

 

 

4.0 

 

 

(0.7)

 

 

95.4 

 

 

0.1 

 

 

98.8 

Net income / (loss)

 

 

9.4 

 

 

(1.4)

 

 

(257.0)

 

 

 -

 

 

(249.0)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash capital expenditures

 

$

27.4 

 

$

 -

 

$

1.0 

 

$

 -

 

$

28.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

3,338.7 

 

$

94.9 

 

$

1,440.1 

 

$

(1,295.9)

 

$

3,577.8 

$ in millions Utility Competitive Retail Other Adjustments and Eliminations DPL Consolidated
For the three months ended September 30, 2015
Revenues from external customers $323.2
 $77.0
 $13.9
 $—
 $414.1
Intersegment revenues 66.0
 —
 1.5
 (67.5) —
Total revenues 389.2
 77.0
 15.4
 (67.5) 414.1
           
Fuel 69.0
 —
 2.4
 —
 71.4
Purchased power 142.5
 66.6
 3.0
 (66.7) 145.4
           
Gross margin $177.7
 $10.4
 $10.0
 $(0.8) $197.3
           
Depreciation and amortization $34.6
 $0.2
 $—
 $—
 $34.8
Interest expense 6.9
 —
 22.1
 (0.1) 28.9
Income tax expense (benefit) 0.8
 1.6
 (2.1) —
 0.3
Net income / (loss) 15.5
 2.6
 (9.5) —
 8.6
           
Cash capital expenditures $27.9
 $0.3
 $0.5
 $—
 $28.7


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



38

Table of Contents

11.


$ in millions Utility Competitive Retail Other Adjustments and Eliminations DPL Consolidated
For the nine months ended September 30, 2015
Revenues from external customers $957.6
 $274.5
 $49.4
 $—
 $1,281.5
Intersegment revenues 245.0
 —
 4.4
 (249.4) —
Total revenues 1,202.6
 274.5
 53.8
 (249.4) 1,281.5
           
Fuel 188.9
 —
 13.3
 —
 202.2
Purchased power 452.3
 247.0
 7.8
 (246.9) 460.2
           
Gross margin $561.4
 $27.5
 $32.7
 $(2.5) $619.1
           
Depreciation and amortization $103.5
 $0.6
 $—
 $—
 $104.1
Interest expense 24.6
 0.1
 65.8
 (0.2) 90.3
Income tax expense (benefit) 25.0
 (2.6) (8.9) —
 13.5
Net income / (loss) 75.9
 10.9
 (27.8) —
 59.0
           
Cash capital expenditures $91.2
 $0.6
 $1.7
 $—
 $93.5
           
at September 30, 2015          
Total assets $3,239.9
 $44.5
 $1,472.8
 $(1,267.8) $3,489.4

$ in millions Utility Competitive Retail Other Adjustments and Eliminations DPL Consolidated
For the nine months ended September 30, 2014
Revenues from external customers $875.9
 $414.9
 $38.8
 $—
 $1,329.6
Intersegment revenues 376.6
 —
 4.1
 (380.7) —
Total revenues 1,252.5
 414.9
 42.9
 (380.7) 1,329.6
           
Fuel 227.4
 —
 8.5
 —
 235.9
Purchased power 457.3
 380.0
 7.1
 (378.2) 466.2
Amortization of intangibles —
 —
 0.9
 —
 0.9
           
Gross margin $567.8
 $34.9
 $26.4
 $(2.5) $626.6
           
Depreciation and amortization $108.2
 $0.6
 $(5.1) $—
 $103.7
Goodwill impairment —
 —
 135.8
 —
 135.8
Fixed-asset impairment —
 —
 11.5
 —
 11.5
Interest expense 25.5
 0.3
 70.5
 (0.5) 95.8
Income tax expense (benefit) 23.1
 2.1
 4.5
 —
 29.7
Net income / (loss) 76.5
 4.2
 (197.5) —
 (116.8)
           
Cash capital expenditures $78.6
 $0.5
 $2.5
 $—
 $81.6
at December 31, 2014          
Total assets $3,338.7
 $94.9
 $1,440.1
 $(1,295.9) $3,577.8



39
Table of Contents

Note 12 – Goodwill Impairment


During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014. In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business. During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit. There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter.

��  

12.


Note 13 – Fixed-asset Impairment


During the first quarter of 2014, DP&L tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L. Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. DP&L performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach. As a result, we recognized an asset impairment expense of $11.5 million. In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend. The sale price approximated the carrying value. This transaction closed on December 30, 2014.


39


40

Table of Contents














FINANCIAL STATEMENTS


The Dayton Power and Light Company

40




41

Table of Contents


THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF OPERATIONS
  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
Revenues $389.2
 $454.9
 $1,202.6
 $1,252.5
         
Cost of revenues:        
Fuel 69.0
 84.5
 188.9
 227.4
Purchased power 142.5
 152.4
 452.3
 457.3
Total cost of revenues 211.5
 236.9
 641.2
 684.7
         
Gross margin 177.7
 218.0
 561.4
 567.8
         
Operating expenses:        
Operation and maintenance 94.5
 85.9
 261.6
 265.9
Depreciation and amortization 34.6
 36.4
 103.5
 108.2
General taxes 20.1
 20.2
 65.0
 67.1
Other —
 —
 0.4
 —
Total operating expenses 149.2
 142.5
 430.5
 441.2
         
Operating income 28.5
 75.5
 130.9
 126.6
         
Other income / (expense), net:        
Investment income —
 0.2
 0.2
 0.6
Interest expense (6.9) (9.4) (24.6) (25.5)
Charge for early retirement of debt (5.0) —
 (5.0) —
Other expense (0.3) —
 (0.6) (2.1)
Total other expense, net (12.2) (9.2) (30.0) (27.0)
         
Earnings before income taxes 16.3
 66.3
 100.9
 99.6
Income tax expense 0.8
 13.1
 25.0
 23.1
         
Net income 15.5
 53.2
 75.9
 76.5
Dividends on preferred stock 0.3
 0.3
 0.7
 0.7
         
Income attributable to common stock $15.2
 $52.9
 $75.2
 $75.8

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



42

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF OPERATIONS

 

 

Three months ended March 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Revenues

 

$

461.3 

 

$

432.1 

 

 

 

 

 

 

 

Cost of revenues:

 

 

 

 

 

 

Fuel

 

 

69.3 

 

 

84.3 

Purchased power

 

 

189.7 

 

 

168.0 

Total cost of revenues

 

 

259.0 

 

 

252.3 

 

 

 

 

 

 

 

Gross margin

 

 

202.3 

 

 

179.8 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

Operation and maintenance

 

 

83.9 

 

 

95.4 

Depreciation and amortization

 

 

34.7 

 

 

36.5 

General taxes

 

 

23.0 

 

 

26.4 

Other

 

 

0.4 

 

 

0.2 

Total operating expenses

 

 

142.0 

 

 

158.5 

 

 

 

 

 

 

 

Operating income

 

 

60.3 

 

 

21.3 

 

 

 

 

 

 

 

Other income / (expense), net:

 

 

 

 

 

 

Investment income / (loss)

 

 

(0.1)

 

 

0.3 

Interest expense

 

 

(8.7)

 

 

(7.8)

Other expense

 

 

(0.2)

 

 

(0.4)

Total other expense

 

 

(9.0)

 

 

(7.9)

 

 

 

 

 

 

 

Earnings before income taxes

 

 

51.3 

 

 

13.4 

Income tax expense

 

 

14.8 

 

 

4.0 

 

 

 

 

 

 

 

Net income

 

 

36.5 

 

 

9.4 

Dividends on preferred stock

 

 

0.2 

 

 

0.2 

 

 

 

 

 

 

 

Income attributable to common stock

 

$

36.3 

 

$

9.2 

 

 

 

 

 

 

 

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

41

Table of Contents


THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
Net income $15.5
 $53.2
 $75.9
 $76.5
Available-for-sale securities activity:        
Change in fair value of available-for-sale securities, net of income tax benefit of $0.1, $0.2, $0.1 and $0.2 for each respective period (0.3) (0.4) (0.3) (0.6)
Reclassification to earnings, net of income tax expense of $0.0, $(0.1), $0.0 and $(0.2) for each respective period —
 0.2
 —
 0.4
Total change in fair value of available-for-sale securities (0.3) (0.2) (0.3) (0.2)
Derivative activity:        
Change in derivative fair value, net of income tax (expense) / benefit of $(4.4), $(0.7), $(5.4) and $9.9 for each respective period 7.8
 1.4
 9.6
 (26.3)
Reclassification to earnings, net of income tax (expense) / benefit of $1.2, $(1.9), $1.9 and $(6.7) for each respective period (2.0) 3.2
 (3.3) 15.3
Total change in fair value of derivatives 5.8
 4.6
 6.3
 (11.0)
Pension and postretirement activity:        
Reclassification to earnings, net of income tax expense of $(0.6), $(0.3), $(1.6) and $(1.0) for each respective period 0.8
 0.7
 2.6
 2.1
Total change in unfunded pension obligation 0.8
 0.7
 2.6
 2.1
Other comprehensive income / (loss) 6.3
 5.1
 8.6
 (9.1)
         
Net comprehensive income $21.8
 $58.3
 $84.5
 $67.4

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


43

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

 

 

Three months ended March 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Net income

 

$

36.5 

 

$

9.4 

 

 

 

 

 

 

 

Available-for-sale securities activity:

 

 

 

 

 

 

Change in fair value of available-for-sale securities, net of income tax (expense) / benefit of $(0.2) and $0.2 for each respective period

 

 

0.5 

 

 

(0.3)

Reclassification to earnings, net of income tax (expense) / benefit of $0.2 and $(0.1) for each respective period

 

 

(0.4)

 

 

0.2 

Total change in fair value of available-for-sale securities

 

 

0.1 

 

 

(0.1)

 

 

 

 

 

 

 

Derivative activity:

 

 

 

 

 

 

Change in derivative fair value, net of income tax benefit of $0.1 and $7.0 for each respective period

 

 

0.1 

 

 

(12.9)

Reclassification to earnings, net of income tax expense of $(0.3) and $(3.2) for each respective period

 

 

0.5 

 

 

5.7 

Total change in fair value of derivatives

 

 

0.6 

 

 

(7.2)

 

 

 

 

 

 

 

Pension and postretirement activity:

 

 

 

 

 

 

Reclassification to earnings, net of income tax expense of $(0.5) and $(0.4) for each respective period

 

 

0.9 

 

 

0.6 

Total change in unfunded pension obligation

 

 

0.9 

 

 

0.6 

 

 

 

 

 

 

 

Other comprehensive income / (loss)

 

 

1.6 

 

 

(6.7)

 

 

 

 

 

 

 

Net comprehensive income

 

$

38.1 

 

$

2.7 

 

 

 

 

 

 

 

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

42

Table of Contents


THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
  September 30, December 31,
$ in millions 2015 2014
ASSETS    
Current assets:    
Cash and cash equivalents $10.7
 $5.4
Restricted cash 13.5
 16.7
Accounts receivable, net (Note 2) 117.1
 152.7
Inventories (Note 2) 95.9
 99.0
Taxes applicable to subsequent years 19.0
 75.4
Regulatory assets, current 29.4
 44.2
Other prepayments and current assets 40.4
 41.1
Total current assets 326.0
 434.5
     
Property, plant & equipment:    
Property, plant & equipment 5,214.0
 5,120.7
Less: Accumulated depreciation and amortization (2,557.4) (2,495.7)
  2,656.6
 2,625.0
Construction work in process 69.8
 75.4
Total net property, plant & equipment 2,726.4
 2,700.4
     
Other non-current assets:    
Regulatory assets, non-current 152.4
 167.5
Intangible assets, net of amortization 4.9
 7.8
Other deferred assets 30.2
 28.5
Total other non-current assets 187.5
 203.8
     
Total assets $3,239.9
 $3,338.7

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



44

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

 

 

Three months ended March 31,

$ in millions

 

2015

 

2014

Cash flows from operating activities:

 

 

 

 

 

 

Net income

 

$

36.5 

 

$

9.4 

Adjustments to reconcile net income to net cash from operating activities:

 

 

 

 

 

 

Depreciation and amortization

 

 

34.7 

 

 

36.5 

Deferred income taxes

 

 

(0.7)

 

 

1.4 

Changes in certain assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 

 

(1.3)

 

 

(14.8)

Inventories

 

 

5.2 

 

 

(10.3)

Prepaid taxes

 

 

0.5 

 

 

0.3 

Taxes applicable to subsequent years

 

 

18.3 

 

 

13.5 

Deferred regulatory costs, net

 

 

11.4 

 

 

(7.7)

Accounts payable

 

 

(20.2)

 

 

34.0 

Accrued taxes payable

 

 

(20.6)

 

 

(21.5)

Accrued interest payable

 

 

(5.9)

 

 

(5.8)

Pension, retiree and other benefits

 

 

2.0 

 

 

0.8 

Other

 

 

(16.3)

 

 

(25.6)

Net cash from operating activities

 

 

43.6 

 

 

10.2 

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

 

Capital expenditures

 

 

(33.1)

 

 

(27.4)

Purchase of emission allowances

 

 

 -

 

 

(0.1)

Purchase of renewable energy credits

 

 

(0.2)

 

 

(1.2)

Decrease / (increase) in restricted cash

 

 

(0.8)

 

 

(16.0)

Insurance proceeds

 

 

1.5 

 

 

 -

Other investing activities, net

 

 

0.3 

 

 

 -

Net cash from investing activities

 

 

(32.3)

 

 

(44.7)

 

 

 

 

 

 

 

Net cash from financing activities:

 

 

 

 

 

 

Dividends paid on common stock to parent

 

 

(10.0)

 

 

 -

Issuance of notes payable - related party

 

 

 -

 

 

15.0 

Dividends paid on preferred stock

 

 

(0.2)

 

 

(0.2)

Borrowings from revolving credit facilities

 

 

15.0 

 

 

 -

Repayment of borrowings from revolving credit facilities

 

 

(15.0)

 

 

 -

Net cash from financing activities

 

 

(10.2)

 

 

14.8 

 

 

 

 

 

 

 

Cash and cash equivalents:

 

 

 

 

 

 

Net change

 

 

1.1 

 

 

(19.7)

Balance at beginning of period

 

 

5.4 

 

 

22.9 

Cash and cash equivalents at end of period

 

$

6.5 

 

$

3.2 

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

 

Interest paid, net of amounts capitalized

 

$

12.5 

 

$

12.8 

Income taxes paid / (refunded), net

 

$

 -

 

$

(0.3)

Non-cash financing and investing activities:

 

 

 

 

 

 

Accruals for capital expenditures

 

$

11.2 

 

$

9.4 

 

 

 

 

 

 

 

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

43

Table of Contents


THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS
  September 30, December 31,
$ in millions 2015 2014
LIABILITIES AND SHAREHOLDER'S EQUITY    
Current liabilities:    
Current portion of long-term debt (Note 5) $444.9
 $0.1
Short-term debt 10.0
 —
Accounts payable 77.6
 104.8
Accrued taxes 128.9
 82.6
Accrued interest 1.2
 9.8
Security deposits 36.2
 34.5
Regulatory liabilities, current 20.5
 4.4
Other current liabilities 46.0
 44.8
Total current liabilities 765.3
 281.0
     
Non-current liabilities:    
Long-term debt (Note 5) 318.0
 877.0
Deferred taxes 626.0
 650.0
Taxes payable 3.0
 78.4
Regulatory liabilities, non-current 125.6
 124.1
Pension, retiree and other benefits 91.2
 95.9
Unamortized investment tax credit 20.6
 22.4
Other deferred credits 90.0
 43.6
Total non-current liabilities 1,274.4
 1,891.4
     
Redeemable preferred stock 22.9
 22.9
     
Commitments and contingencies (Note 11) 
 
     
Common shareholder's equity:    
Common stock, at par value of $0.01 per share: 0.4
 0.4
Other paid-in capital 803.6
 803.5
Accumulated other comprehensive loss (33.7) (42.3)
Retained earnings 407.0
 381.8
Total common shareholder's equity 1,177.3
 1,143.4
Total liabilities and shareholder's equity $3,239.9
 $3,338.7

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


45

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

6.5 

 

$

5.4 

Restricted cash

 

 

17.5 

 

 

16.7 

Accounts receivable, net (Note 2)

 

 

155.0 

 

 

152.7 

Inventories (Note 2)

 

 

93.7 

 

 

99.0 

Taxes applicable to subsequent years

 

 

57.1 

 

 

75.4 

Regulatory assets, current

 

 

34.9 

 

 

44.2 

Other prepayments and current assets

 

 

36.9 

 

 

41.1 

Total current assets

 

 

401.6 

 

 

434.5 

 

 

 

 

 

 

 

Property, plant & equipment:

 

 

 

 

 

 

Property, plant & equipment

 

 

5,152.9 

 

 

5,120.7 

Less: Accumulated depreciation and amortization

 

 

(2,524.3)

 

 

(2,495.7)

 

 

 

2,628.6 

 

 

2,625.0 

Construction work in process

 

 

64.3 

 

 

75.4 

Total net property, plant & equipment

 

 

2,692.9 

 

 

2,700.4 

 

 

 

 

 

 

 

Other non-current assets:

 

 

 

 

 

 

Regulatory assets, non-current

 

 

156.8 

 

 

167.5 

Intangible assets, net of amortization

 

 

4.4 

 

 

7.8 

Other deferred assets

 

 

34.0 

 

 

28.5 

Total other non-current assets

 

 

195.2 

 

 

203.8 

 

 

 

 

 

 

 

Total assets

 

$

3,289.7 

 

$

3,338.7 

 

 

 

 

 

 

 

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

44

Table of Contents


 

 

 

 

 

 

 

 

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Current portion of long-term debt (Note 4)

 

$

0.1 

 

$

0.1 

Accounts payable

 

 

78.1 

 

 

104.8 

Accrued taxes

 

 

99.7 

 

 

82.6 

Accrued interest

 

 

3.9 

 

 

9.8 

Customer security deposits

 

 

16.1 

 

 

34.5 

Regulatory liabilities, current

 

 

6.8 

 

 

4.4 

Other current liabilities

 

 

44.0 

 

 

44.8 

Total current liabilities

 

 

248.7 

 

 

281.0 

 

 

 

 

 

 

 

Non-current liabilities:

 

 

 

 

 

 

Long-term debt (Note 4)

 

 

877.1 

 

 

877.0 

Deferred taxes

 

 

641.3 

 

 

650.0 

Taxes payable

 

 

40.7 

 

 

78.4 

Regulatory liabilities, non-current

 

 

124.6 

 

 

124.1 

Pension, retiree and other benefits

 

 

95.9 

 

 

95.9 

Unamortized investment tax credit

 

 

21.8 

 

 

22.4 

Other deferred credits

 

 

45.6 

 

 

43.6 

Total non-current liabilities

 

 

1,847.0 

 

 

1,891.4 

 

 

 

 

 

 

 

Redeemable preferred stock

 

 

22.9 

 

 

22.9 

 

 

 

 

 

 

 

Commitments and contingencies (Note 10)

 

 

 

 

 

 

 

 

 

 

 

 

 

Common shareholder's equity:

 

 

 

 

 

 

Common stock, at par value of $0.01 per share:

 

 

0.4 

 

 

0.4 

Other paid-in capital

 

 

803.5 

 

 

803.5 

Accumulated other comprehensive loss

 

 

(40.7)

 

 

(42.3)

Retained earnings

 

 

407.9 

 

 

381.8 

Total common shareholder's equity

 

 

1,171.1 

 

 

1,143.4 

 

 

 

 

 

 

 

Total liabilities and shareholder's equity

 

$

3,289.7 

 

$

3,338.7 

 

 

 

 

 

 

 

See Notes to Condensed Financial Statements.

 

 

 

 

 

 

These interim statements are unaudited.

 

 

 

 

 

 

45

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
  Nine months ended September 30,
$ in millions 2015 2014
Cash flows from operating activities:    
Net income $75.9
 $76.5
Adjustments to reconcile net income to net cash from operating activities:    
Depreciation and amortization 103.5
 108.2
Deferred income taxes (14.2) 2.9
Changes in certain assets and liabilities:    
Accounts receivable 37.3
 4.8
Inventories 3.0
 (3.5)
Prepaid taxes (0.4) 0.2
Taxes applicable to subsequent years 56.4
 50.5
Deferred regulatory costs, net 27.6
 4.8
Accounts payable (20.0) 7.9
Accrued taxes payable (29.1) (40.8)
Accrued interest payable (8.8) (5.7)
Pension, retiree and other benefits 1.0
 (5.2)
Other 15.5
 (11.4)
Net cash provided by operating activities 247.7
 189.2
Cash flows from investing activities:    
Capital expenditures (91.2) (78.6)
Purchase of emission allowances —
 (0.2)
Purchase of renewable energy credits (0.6) (3.4)
Increase / (decrease) in restricted cash 3.2
 (9.4)
Insurance proceeds 4.3
 0.4
Other investing activities, net 0.4
 1.1
Net cash used by investing activities (83.9) (90.1)
Net cash from financing activities:    
Dividends paid on common stock to parent (50.0) (90.0)
Borrowings from revolving credit facilities 50.0
 —
Repayment of borrowings from revolving credit facilities (40.0) —
Issuance of notes payable - related party —
 15.0
Repayment of notes payable - related party —
 (15.0)
Dividends paid on preferred stock (0.7) (0.7)
Payments of deferred financing costs (3.3) (0.2)
Issuance of long-term debt 200.0
 —
Retirement of long-term debt (314.5) (0.1)
Net cash used by financing activities (158.5) (91.0)
     
Cash and cash equivalents:    
Net change 5.3
 8.1
Balance at beginning of period 5.4
 22.9
Cash and cash equivalents at end of period $10.7
 $31.0
Supplemental cash flow information:    
Interest paid, net of amounts capitalized $26.8
 $26.1
Income taxes paid / (refunded), net $0.8
 $0.2
Non-cash financing and investing activities:    
Accruals for capital expenditures $12.6
 $6.7
See Notes to Condensed Financial Statements.
These interim statements are unaudited.


46

Table of Contents


The Dayton Power and Light Company

Notes to Condensed Financial Statements (Unaudited)

1.


Note 1 – Overview and Summary of Significant Accounting Policies


Description of Business

DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission retail services are still regulated. DP&L has the exclusive right to provide such distribution and transmission services to its more than 516,000 515,000 customers located in West Central Ohio. Additionally, DP&L offers retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L owns multiple coal-fired and peaking electric generating facilities as well as numerous transmission facilities, all of which are included in the financial statements at amortized cost. During 2015, DP&Lis required to source 60% of the generation for its SSO customers through a competitive bid process followed byand beginning January 2016, generation for its SSO customers will be 100% in 2016 and later.competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns, retail competition in our service territory and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. On June 4, 2014, the PUCO issued a fourthan entry on rehearing which reinstated the time by whichrequires DP&L mustto separate its generation assets from its transmission and distribution assets to no later than January 1, 2017.  While the OCC filed an application for rehearing on this Commission Order, it was denied by final order issued on July 23, 2014. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of DPLER’s retail customers.DP&L is a subsidiary of DPL.


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


DP&L employed 1,1661,194 people as of March 31,September 30, 2015. Approximately 61% of all employees are under a collective bargaining agreement which expires on October 31, 2017.


Financial Statement Presentation

DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five coal-fired generating facilities, peaking electric generating facilities and numerous transmission facilities, all of which are included in the financial statements at amortized cost. Operating revenues and expenses of these facilities are included on a pro rata basis in the corresponding lines in the Condensed Statements of Operations. See Note 34 for more information.


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

These financial statements have been prepared in accordance with GAAP for interim financial statements, the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2014.


In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial position as of March 31,September 30, 2015; our results of operations for the three and nine months ended March 31,September 30, 2015 and 2014 and our cash flows for the threenine months ended March 31,September 30, 2015 and 2014. Unless otherwise noted, all adjustments are normal and recurring in nature.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 threenine months ended March 31,September 30, 2015 may not be indicative of our results that will be realized for the full year ending December 31, 2015.


The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment;

unbilled

46


47

Table of Contents

unbilled


revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; intangibles and assets and liabilities related to employee benefits.    

benefits; goodwill; and intangibles.


Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DP&L collects certain excise taxes levied by state or local governments from its customers. These taxes are accounted for on a net basis and not included in revenue. The amounts of such taxes collected for the three months ended March 31,September 30, 2015 and 2014 were $14.0$13.0 million and $14.4$12.5 million, respectively. The amounts of such taxes collected for the nine months ended September 30, 2015 and 2014 were $38.5 million and $38.5 million, respectively.


Related Party Transactions

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

DP&L charges the Service Company for employee payroll and benefit costs that are incurred on behalf of the Service Company.


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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

March 31,

$ in millions

 

2015

 

2014

DP&L Revenues:

 

 

 

 

 

 

Sales to DPLER (including MC Squared) (a)

 

$

110.7 

 

$

139.5 

 

 

 

 

 

 

 

DP&L Operations and Maintenance Expenses:

 

 

 

 

 

 

Premiums paid for insurance services provided by MVIC (b)

 

$

(0.7)

 

$

(0.8)

Expense recoveries for services provided to DPLER (c)

 

$

0.8 

 

$

 -

 

 

 

 

 

 

 

Transactions with the Service Company

 

 

 

 

 

 

Charges for services provided

 

$

8.4 

 

$

10.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L Customer security deposits:

 

At March 31, 2015

 

At December 31, 2014

Deposits received from DPLER (d)

 

$

2.4 

 

$

20.1 

 

 

 

 

 

 

 

Balances with the Service Company

 

 

 

 

 

 

Net advances / (payable) to the Service Company

 

$

3.0 

 

$

(4.7)
  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
DP&L Revenues:
        
Sales to DPLER (including MC Squared) (a)
 $66.0
 $125.6
 $245.0
 $376.6
DP&L Operations and Maintenance Expenses:
        
Premiums paid for insurance services provided by MVIC (b)
 $(0.8) $(0.7) $(2.4) $(2.1)
Expense recoveries for services provided to DPLER (c)
 $0.6
 $0.5
 $1.8
 $1.6
Transactions with the Service Company        
Charges from the Service Company $7.6
 $7.4
 $24.3
 $24.2
Charges to the Service Company $1.1
 $0.6
 $5.0
 $1.7

(a)DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers.  The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements.

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

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

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

47


DP&L Customer security deposits:
 at September 30, 2015 at December 31, 2014
Deposits received from DPLER (d)
 $2.9
 $20.1
Balances with the Service Company    
Net prepaid / (payable) to the service company $0.1
 $(4.7)

(a)
DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements.
(b)
MVIC, a wholly owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC. DP&L received insurance proceeds from MVIC of $0.5 million and $0.0 million for the three months ended September 30, 2015 and 2014, respectively, and $4.3 million and $0.4 million for the nine months ended September 30, 2015 and 2014, respectively.
(c)
In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include, but are not limited to, employee-related expenses, accounting, information technology, payroll, legal and other administrative expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded.
(d)
DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity. Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.



48

Table of Contents


Recently Issued Accounting Standards


ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30)

In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of March 31,September 30, 2015, DP&L had approximately $10.4$4.6 million in deferred financing costs classified in other noncurrentnon-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.

2.


ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contract with Customer (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. We have not yet selected a transition method and we are currently evaluating the impact of adopting the standard on our financial statements.

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

ASU No. 2015-02, Consolidation — Amendments to the Consolidation Analysis (Topic 810)
In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the VIE guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our financial statements.

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

ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The


49
Table of Contents

standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. We have not yet selected a transition method and we are currently evaluating the impact of adopting the standard on our financial statements.

Note 2 – Supplemental Financial Information


Accounts receivable and Inventories are as follows at March 31,September 30, 2015 and December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Accounts receivable, net:

 

 

 

 

 

 

Unbilled revenue

 

$

40.6 

 

$

49.0 

Customer receivables

 

 

81.7 

 

 

68.7 

Amounts due from partners in jointly owned plants

 

 

8.3 

 

 

14.2 

Other

 

 

25.5 

 

 

21.7 

Provision for uncollectible accounts

 

 

(1.1)

 

 

(0.9)

Total accounts receivable, net

 

$

155.0 

 

$

152.7 

 

 

 

 

 

 

 

Inventories, at average cost:

 

 

 

 

 

 

Fuel and limestone

 

$

58.8 

 

$

65.3 

Plant materials and supplies

 

 

33.1 

 

 

32.3 

Other

 

 

1.8 

 

 

1.4 

Total inventories, at average cost

 

$

93.7 

 

$

99.0 

48

  September 30, December 31,
$ in millions 2015 2014
Accounts receivable, net:    
Unbilled revenue $34.8
 $49.0
Customer receivables 63.6
 68.7
Amounts due from partners in jointly owned plants 12.0
 14.2
Other 7.6
 21.7
Provision for uncollectible accounts (0.9) (0.9)
Total accounts receivable, net $117.1
 $152.7
     
Inventories, at average cost:    
Fuel and limestone $60.4
 $65.3
Plant materials and supplies 33.6
 32.3
Other 1.9
 1.4
Total inventories, at average cost $95.9
 $99.0

Table of Contents


Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the three and nine months ended March 31,September 30, 2015 and 2014 are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Details about Accumulated Other Comprehensive Income / (Loss) components

 

Affected line item in the Condensed Statements of Operations

 

Three months ended

 

 

 

 

March 31,

$ in millions

 

 

 

2015

 

2014

 

 

 

 

 

 

 

 

 

Gains and losses on Available-for-sale securities activity (Note 7):

 

 

 

 

 

 

 

 

Other income

 

$

(0.6)

 

$

0.3 

 

 

Tax expense

 

 

0.2 

 

 

(0.1)

 

 

Net of income taxes

 

 

(0.4)

 

 

0.2 

 

 

 

 

 

 

 

 

 

Gains and losses on cash flow hedges (Note 8):

 

 

 

 

 

 

 

 

Interest expense

 

 

(0.3)

 

 

(0.3)

 

 

Revenue

 

 

(0.3)

 

 

(1.0)

 

 

Purchased power

 

 

1.4 

 

 

10.2 

 

 

Total before income taxes

 

 

0.8 

 

 

8.9 

 

 

Tax expense

 

 

(0.3)

 

 

(3.2)

 

 

Net of income taxes

 

 

0.5 

 

 

5.7 

 

 

 

 

 

 

 

 

 

Amortization of defined benefit pension items (Note 6):

 

 

 

 

 

 

 

 

Reclassification to Other income / (deductions)

 

 

1.4 

 

 

1.0 

 

 

Tax benefit

 

 

(0.5)

 

 

(0.4)

 

 

Net of income taxes

 

 

0.9 

 

 

0.6 

 

 

 

 

 

 

 

 

 

Total reclassifications for the period, net of income taxes

 

$

1.0 

 

$

6.5 

Details about Accumulated Other Comprehensive Income / (Loss) components Affected line item in the Condensed Statements of Operations Three months ended Nine months ended
    September 30, September 30,
$ in millions   2015 2014 2015 2014
Gains and losses on Available-for-sale securities activity (Note 8):      
  Other income $—
 $0.3
 $—
 $0.6
  Tax expense —
 (0.1) —
 (0.2)
  Net of income taxes —
 0.2
 —
 0.4
Gains and losses on cash flow hedges (Note 9):        
  Interest expense (0.3) (0.2) (0.9) (0.8)
  Revenue (3.8) 4.9
 (7.0) 23.4
  Purchased power 0.9
 0.4
 2.7
 (0.6)
  Total before income taxes (3.2) 5.1
 (5.2) 22.0
  Tax expense 1.2
 (1.9) 1.9
 (6.7)
  Net of income taxes (2.0) 3.2
 (3.3) 15.3
Amortization of defined benefit pension items (Note 7):        
  Reclassification to Other income / (deductions) 1.4
 1.0
 4.2
 3.1
  Tax benefit (0.6) (0.3) (1.6) (1.0)
  Net of income taxes 0.8
 0.7
 2.6
 2.1
           
Total reclassifications for the period, net of income taxes $(1.2) $4.1
 $(0.7) $17.8


50
Table of Contents


The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the threenine months ended March 31,September 30, 2015 are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Gains / (losses) on available-for-sale securities

 

Gains / (losses) on cash flow hedges

 

Change in unfunded pension obligation

 

Total

Balance January 1, 2015

 

$

0.7 

 

$

2.8 

 

$

(45.8)

 

$

(42.3)

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income before reclassifications

 

 

0.5 

 

 

0.1 

 

 

 -

 

 

0.6 

Amounts reclassified from accumulated other comprehensive income / (loss)

 

 

(0.4)

 

 

0.5 

 

 

0.9 

 

 

1.0 

Net current period other comprehensive income

 

 

0.1 

 

 

0.6 

 

 

0.9 

 

 

1.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance March 31, 2015

 

$

0.8 

 

$

3.4 

 

$

(44.9)

 

$

(40.7)

49

$ in millions Gains / (losses) on available-for-sale securities Gains / (losses) on cash flow hedges Change in unfunded pension obligation Total
Balance January 1, 2015 $0.7
 $2.8
 $(45.8) $(42.3)
         
Other comprehensive income before reclassifications (0.3) 9.6
 —
 9.3
Amounts reclassified from accumulated other comprehensive income / (loss) —
 (3.3) 2.6
 (0.7)
Net current period other comprehensive income / (loss) (0.3) 6.3
 2.6
 8.6
         
Balance September 30, 2015 $0.4
 $9.1
 $(43.2) $(33.7)


Table
Note 3 – Regulatory assets and liabilities

DP&L has certain rate riders that provide for recovering, on a timely basis, costs incurred for specific programs for which costs may fluctuate. These riders generally allow DP&L to estimate future costs and customer kWh consumption and set rider rates designed to recover those estimated costs as they are incurred. Differences between revenues collected and the actual program costs are tracked and reconciled by increasing or reducing future rates accordingly. DP&L’s current regulatory assets and current regulatory liabilities reflect the reconciliation of Contentssuch differences, with the exception of deferred storm costs. The deferred storm regulatory asset reflects costs incurred to repair major storm damage in previous years, for which DP&L was granted cost recovery during 2015. The changes in DP&L’s current regulatory asset and liability balances from December 31, 2014 to September 30, 2015 primarily represent the recovery of $16.7 million of deferred storm costs, and the reconciliation of other rider costs.

3.

Note 4 – Ownership of Coal-fired Facilities


DP&L has undivided ownership interests in five coal-fired electric generating facilities, various peaking facilities and numerous transmission facilities with certain other Ohio utilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on thetheir energy taken.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. As of March 31,At September 30, 2015, DP&L had $24.0$25.0 million of construction work in process at such jointly owned facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant &and equipment in the Condensed Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned unit or station. units and stations.




51
Table of Contents

DP&L’s undivided ownership interest in such facilities at March 31,September 30, 2015, is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L Share

 

 

DP&L Carrying value

Jointly owned production units and stations:

 

Ownership
(%)

 

Summer Production Capacity (MW)

 

Gross Plant in Service
($ in millions)

 

Accumulated Depreciation
($ in millions)

 

Construction Work in Process
($ in millions)

 

SCR and FGD Equipment Installed and in Service (Yes/No)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Conesville Unit 4

 

16.5

 

129 

 

$

24 

 

$

5 

 

$

1 

 

Yes

Killen Station

 

67.0

 

402 

 

 

624 

 

 

317 

 

 

4 

 

Yes

Miami Fort Units 7 and 8

 

36.0

 

368 

 

 

361 

 

 

164 

 

 

3 

 

Yes

Stuart Station

 

35.0

 

808 

 

 

758 

 

 

327 

 

 

12 

 

Yes

Zimmer Station

 

28.1

 

371 

 

 

1,104 

 

 

679 

 

 

4 

 

Yes

Transmission (at varying percentages)

 

 

 

n/a

 

 

98 

 

 

63 

 

 

 -

 

 

Total

 

 

 

2,078 

 

$

2,969 

 

$

1,555 

 

$

24 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4.

  DP&L Share DP&L Carrying value
Jointly owned production units and stations: 
Ownership
(%)
 Summer Production Capacity (MW) 
Gross Plant in Service
($ in millions)
 
Accumulated Depreciation
($ in millions)
 
Construction Work in Process
($ in millions)
 SCR and FGD Equipment Installed and in Service (Yes/No)
Conesville Unit 4 16.5 129
 $25
 $8
 $1
 Yes
Killen Station 67.0 402
 655
 324
 1
 Yes
Miami Fort Units 7 and 8 36.0 368
 365
 169
 4
 Yes
Stuart Station 35.0 808
 771
 335
 14
 Yes
Zimmer Station 28.1 371
 1,104
 688
 5
 Yes
Transmission (at varying percentages)   n/a 98
 63
 —
  
Total   2,078
 $3,018
 $1,587
 $25
  

Note 5 – Debt Obligations 


Long-term debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

First mortgage bonds due in September 2016 - 1.875%

 

 

445.0 

 

 

445.0 

Pollution control series due in January 2028 - 4.7%

 

$

35.3 

 

$

35.3 

Pollution control series due in January 2034 - 4.8%

 

 

179.1 

 

 

179.1 

Pollution control series due in September 2036 - 4.8%

 

 

100.0 

 

 

100.0 

Pollution control series due in November 2040 - rates from: 0.02% - 0.05% and 0.04% - 0.15% (a)

 

 

100.0 

 

 

100.0 

U.S. Government note due in February 2061 - 4.2%

 

 

18.1 

 

 

18.1 

Unamortized debt discount

 

 

(0.4)

 

 

(0.5)

Total non-current portion of long-term debt

 

$

877.1 

 

$

877.0 

50

  September 30, December 31,
$ in millions 2015 2014
First mortgage bonds due in September 2016 - 1.875% $—
 $445.0
Pollution control series due in January 2028 - 4.7% —
 35.3
Pollution control series due in January 2034 - 4.8% —
 179.1
Pollution control series due in September 2036 - 4.8% 100.0
 100.0
Pollution control series due in August 2020 - 1.13% - 1.14% 200.0
 —
Pollution control series due in November 2040 - rates from: 0.02% - 0.12% and 0.04% - 0.15% (a) —
 100.0
U.S. Government note due in February 2061 - 4.2% 18.0
 18.1
Unamortized debt discount —
 (0.5)
Total non-current portion of long-term debt $318.0
 $877.0

Table of Contents


Current portion of long-term debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31,

 

December 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

U.S. Government note due in February 2061 - 4.2%

 

 

0.1 

 

$

0.1 

Total current portion of long-term debt

 

$

0.1 

 

$

0.1 

  September 30, December 31,
$ in millions 2015 2014
First mortgage bonds due in September 2016 - 1.875% $445.0
 $—
U.S. Government note due in February 2061 - 4.2% 0.1
 0.1
Unamortized debt discount (0.2) —
Total current portion of long-term debt $444.9
 $0.1

(a)Range of interest rates for the threenine months ended March 31,September 30, 2015 and the twelve months ended December 31, 2014, respectively.

At March 31, 2015, maturities of long-term debt are as follows:

 

 

 

 

 

 

 

 

Due within the twelve months ending March 31,

 

 

 

$ in millions

 

 

 

2016

 

$

0.1 

2017

 

 

445.1 

2018

 

 

0.1 

2019

 

 

0.2 

2020

 

 

0.2 

Thereafter

 

 

431.9 

 

 

 

877.6 

 

 

 

 

Unamortized discounts

 

 

(0.4)

Total long-term debt

 

$

877.2 

 

 

 

 


DP&L has a $300.0 millionan unsecured revolving credit agreement with a syndicated bank group. ThisPrior to refinancing the facility on July 31, 2015, as discussed below, this facility had a $300.0 million facility hasborrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that gave DP&L the ability to increase the size of the facility by an additional $100.0 million. On July 31, 2015, DP&L refinanced its revolving credit facility, reducing the total size from $300.0 million to $175.0 million, with a $50.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million. This refinancing extended the life of the facility from May 2018 to July 2020. At March 31,September 30, 2015, there wereDP&L had drawn $10.0 million under this facility and had two letters of credit in the amount of $1.4 million outstanding under this facility, with the remaining $298.6$163.6 million available to DP&L. Fees associated with this revolvingletter of credit facility were not material during the threenine months ended March 31,September 30, 2015 or 2014.



52
Table of Contents


On July 1, 2015, the $35.3 million of 4.7% pollution control bonds due January 2028 and $41.3 million of the 4.8% pollution control bonds due January of 2034 became callable at par and were redeemed with cash.

On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bonds due November 2040 and $137.8 million of 4.8% pollution control bonds due January of 2034. These bonds were refinanced with $200.0 million of new pollution control bonds at variable rates of interest secured by first mortgage bonds in an equivalent amount and the remaining $37.8 million of these bonds was redeemed.

DP&L’s unsecured revolving credit agreements and DP&L’s standby letter of credit have two financial covenants, thecovenants. The first financial covenant measures Total Debt to Total Capitalization. The Total Debt to Total Capitalization ratio is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant compares EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The above covenants were retained with some amendments in

DP&L's revolving credit facility refinanced on July 31, 2015. The DP&L amended standby letter of credit facilities were terminated on August 3, 2015.


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

5.


Note 6 – Income Taxes


The following table details the effective tax rates for the three and nine months ended March 31,September 30, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended March 31,

 

 

 

2015

 

 

2014

DP&L

 

 

29.0%

 

 

29.9%

  Three months ended September 30, Nine months ended September 30,
  2015 2014 2015 2014
DP&L 4.9% 19.8% 24.8% 23.2%

Income tax expense for the three and nine months ended March 31,September 30, 2015 and 2014 was calculated using the estimated annual effective income tax rates for 2015 and 2014 of 29.4%29.0% and 30.6%30.5%, respectively. For the three and nine months ended March 31,September 30, 2015 and 2014 management estimated the annual effective tax rate based on its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to

51

Table of Contents

the most recent interim period, the rates estimated could be materially different from the actual effective tax rates.


For the three and nine months ended March 31,September 30, 2015, DP&L’scurrent period effective rate is less than the estimated annual effective rate primarily due to a discrete adjustment that was recordedthe anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return to properly reflectinclude the filed 2013 state income tax returnsdomestic manufacturing deduction and the deduction for the preferred stock dividends.

6.


Note 7 – Pension and Postretirement Benefits


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


We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of ERISA and, in addition, make voluntary contributions from time to time. There were nowas $5.0 million and $0.0 million in employer contributions made during the threenine months ended March 31,September 30, 2015 or 2014.  

and 2014, respectively.


The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP, in the aggregate. The amounts presented for postretirement include both health and life insurance. The pension and postretirement costs below have not been adjusted for amounts billed to the Service Company for former DP&L employees who are now employed by the Service Company but are still participants in the DP&L plan. See "Related Party Transactions" discussion in Note 1, "Overview"Overview and Summary of Significant Accounting Policies"Policies".




53
Table of Contents

The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the three and nine months ended March 31,September 30, 2015 and 2014 was:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Periodic Benefit Cost / (Income)

Pension

 

Postretirement

 

 

Three months ended

 

Three months ended

 

 

March 31,

 

March 31,

$ in millions

 

2015

 

2014

 

2015

 

2014

Service cost

 

$

1.8 

 

$

1.5 

 

$

 -

 

$

 -

Interest cost

 

 

4.3 

 

 

4.4 

 

 

0.2 

 

 

0.2 

Expected return on plan assets

 

 

(5.7)

 

 

(5.7)

 

 

 -

 

 

 -

Amortization of unrecognized:

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost

 

 

0.8 

 

 

0.7 

 

 

 -

 

 

 -

Actuarial loss / (gain)

 

 

2.4 

 

 

1.6 

 

 

(0.2)

 

 

(0.2)

Net periodic benefit cost

 

$

3.6 

 

$

2.5 

 

$

 -

 

$

 -


 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

$ in millions

 

Pension

 

Postretirement

 

 

 

 

 

 

 

2015

 

$

18.6 

 

$

1.4 

2016

 

 

25.2 

 

 

1.8 

2017

 

 

25.7 

 

 

1.7 

2018

 

 

26.3 

 

 

1.6 

2019

 

 

26.7 

 

 

1.5 

2020 - 2024

 

 

137.0 

 

 

6.1 

7.

Net Periodic Benefit Cost Pension Postretirement
  Three months ended Three months ended
  September 30, September 30,
$ in millions 2015 2014 2015 2014
Service cost $1.8
 $1.5
 $0.1
 $—
Interest cost 4.2
 4.3
 0.1
 0.2
Expected return on plan assets (5.6) (5.7) (0.1) (0.1)
Amortization of unrecognized:        
Prior service cost 0.9
 0.7
 0.1
 0.1
Actuarial loss / (gain) 2.4
 1.6
 (0.2) (0.2)
Net periodic benefit cost $3.7
 $2.4
 $—
 $—

Net Periodic Benefit Cost Pension Postretirement
  Nine months ended Nine months ended
  September 30, September 30,
$ in millions 2015 2014 2015 2014
Service cost $5.3
 $4.4
 $0.1
 $0.1
Interest cost 12.8
 13.0
 0.5
 0.6
Expected return on plan assets (16.8) (17.0) (0.1) (0.2)
Amortization of unrecognized:        
Prior service cost 2.5
 2.1
 0.1
 0.1
Actuarial loss / (gain) 7.2
 4.8
 (0.5) (0.5)
Net periodic benefit cost $11.0
 $7.3
 $0.1
 $0.1

Benefit payments and Medicare Part D reimbursements, which reflect future service, are estimated to be paid as follows:
$ in millions Pension Postretirement
2015 $6.2
 $0.5
2016 25.2
 1.8
2017 25.7
 1.7
2018 26.3
 1.6
2019 26.7
 1.5
2020 - 2024 137.0
 6.1

Note 8 – Fair Value Measurements


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

52




54

Table of Contents


The following table presents the fair value and cost of our non-derivative instruments at March 31,September 30, 2015 and December 31, 2014. Information about the fair value of our derivative instruments can be found in Note 8.    

9.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2015

 

December 31, 2014

$ in millions

 

Carrying Value

 

Fair Value

 

Carrying Value

 

Fair Value

Assets

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

0.1 

 

$

0.1 

 

$

0.1 

 

$

0.1 

Equity securities

 

 

2.7 

 

 

3.8 

 

 

2.7 

 

 

3.7 

Debt securities

 

 

4.6 

 

 

4.6 

 

 

4.7 

 

 

4.7 

Hedge funds

 

 

0.7 

 

 

0.7 

 

 

0.8 

 

 

0.8 

Real estate

 

 

0.3 

 

 

0.4 

 

 

0.4 

 

 

0.4 

Total assets

 

$

8.4 

 

$

9.6 

 

$

8.7 

 

$

9.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Debt

 

$

877.2 

 

$

885.2 

 

$

877.1 

 

$

882.5 

  September 30, 2015 December 31, 2014
$ in millions Cost Fair Value Cost Fair Value
Assets        
Money market funds $0.2
 $0.2
 $0.1
 $0.1
Equity securities 2.7
 3.4
 2.7
 3.7
Debt securities 4.5
 4.4
 4.7
 4.7
Hedge funds 0.7
 0.7
 0.8
 0.8
Real estate 0.3
 0.3
 0.4
 0.4
Total assets $8.4
 $9.0
 $8.7
 $9.7
Liabilities        
Debt $762.9
 $764.3
 $877.1
 $882.5

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


Debt

Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value,cost, net of unamortized premium or discount in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2016 to 2061.


Master Trust Assets

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


DP&L had $0.7 million ($0.5 million after tax) of unrealized gains and $0.1 million ($0.1 million after tax) of unrealized losses on the Master Trust assets in AOCI at September 30, 2015 and $1.1 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at MarchDecember 31, 2014.

During the nine months ended September 30, 2015, and $1.1$1.0 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014. 

During the three months ended March 31, 2015, $0.6 million ($0.4 million after tax) of various investments were sold to facilitate the distribution of benefits and the unrealized gains were reversed into earnings. An immaterial amount of unrealized gains are expected to be reversed to earnings over the next twelve months to facilitate the disbursement of benefits.


Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:

·

Level 1 (quoted prices in active markets for identical assets or liabilities);

·

Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active)Level 1 (quoted prices in active markets for identical assets or liabilities);

·

Level 3 (unobservable inputs).

Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active);

Level 3 (unobservable inputs).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.


53


55

Table of Contents


We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the three months and nine months ended MarchSeptember 30, 2015 and 2014.


The fair value of assets and liabilities at March 31,September 30, 2015 and December 31, 2014 and the respective category within the fair value hierarchy for DP&L was determined as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets and Liabilities at Fair Value

 

 

 

 

Level 1

 

Level 2

 

Level 3

$ in millions

 

Fair Value at March 31, 2015

 

Based on Quoted Prices in Active Markets

 

Other Observable Inputs

 

Unobservable Inputs

Assets

 

 

 

 

 

 

 

 

 

 

 

 

Master Trust assets

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

0.1 

 

$

0.1 

 

$

 -

 

$

 -

Equity securities

 

 

3.8 

 

 

 -

 

 

3.8 

 

 

 -

Debt securities

 

 

4.6 

 

 

 -

 

 

4.6 

 

 

 -

Hedge funds

 

 

0.7 

 

 

 -

 

 

0.7 

 

 

 -

Real estate

 

 

0.4 

 

 

 -

 

 

0.4 

 

 

 -

Total Master Trust assets

 

 

9.6 

 

 

0.1 

 

 

9.5 

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

FTRs

 

 

0.3 

 

 

 -

 

 

 -

 

 

0.3 

Forward power contracts

 

 

20.5 

 

 

 -

 

 

19.0 

 

 

1.5 

Total derivative assets

 

 

20.8 

 

 

 -

 

 

19.0 

 

 

1.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

30.4 

 

$

0.1 

 

$

28.5 

 

$

1.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Heating oil

 

$

0.3 

 

$

0.3 

 

$

 -

 

$

 -

Forward power contracts

 

 

20.6 

 

 

 -

 

 

19.2 

 

 

1.4 

Total derivative liabilities

 

 

20.9 

 

 

0.3 

 

 

19.2 

 

 

1.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

 

885.2 

 

 

 -

 

 

867.0 

 

 

18.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liabilities

 

$

906.1 

 

$

0.3 

 

$

886.2 

 

$

19.6 

54

Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair value at September 30, 2015 Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs
Assets        
Master Trust assets        
Money market funds $0.2
 $0.2
 $—
 $—
Equity securities 3.4
 —
 3.4
 —
Debt securities 4.4
 —
 4.4
 —
Hedge funds 0.7
 —
 0.7
 —
Real estate 0.3
 —
 0.3
 —
Total Master Trust assets 9.0
 0.2
 8.8
 —
         
Derivative assets        
FTRs 0.4
 —
 —
 0.4
Forward power contracts 30.2
 —
 30.2
 —
Total derivative assets 30.6
 —
 30.2
 0.4
         
Total assets $39.6
 $0.2
 $39.0
 $0.4
Liabilities        
Derivative liabilities        
FTRs $0.7
 $—
 $—
 $0.7
Forward power contracts 24.5
 —
 22.3
 2.2
Total derivative liabilities 25.2
 —
 22.3
 2.9
         
Debt 764.3
 —
 746.2
 18.1
         
Total liabilities $789.5
 $—
 $768.5
 $21.0


56

Table of Contents


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets and Liabilities at Fair Value

 

 

 

 

Level 1

 

Level 2

 

Level 3

$ in millions

 

Fair Value at December 31, 2014

 

Based on Quoted Prices in Active Markets

 

Other Observable Inputs

 

Unobservable Inputs

Assets

 

 

 

 

 

 

 

 

 

 

 

 

Master Trust assets

 

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

0.1 

 

$

0.1 

 

$

 -

 

$

 -

Equity securities

 

 

3.7 

 

 

 -

 

 

3.7 

 

 

 -

Debt securities

 

 

4.7 

 

 

 -

 

 

4.7 

 

 

 -

Hedge funds

 

 

0.8 

 

 

 -

 

 

0.8 

 

 

 -

Real estate

 

 

0.4 

 

 

 -

 

 

0.4 

 

 

 -

Total Master Trust assets

 

 

9.7 

 

 

0.1 

 

 

9.6 

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets

 

 

 

 

 

 

 

 

 

 

 

 

Forward power contracts

 

 

15.1 

 

 

 -

 

 

13.9 

 

 

1.2 

Total Derivative assets

 

 

15.1 

 

 

 -

 

 

13.9 

 

 

1.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

24.8 

 

$

0.1 

 

$

23.5 

 

$

1.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Derivative liabilities

 

 

 

 

 

 

 

 

 

 

 

 

FTRs

 

$

0.6 

 

$

 -

 

$

 -

 

$

0.6 

Heating oil futures

 

 

0.4 

 

 

0.4 

 

 

 -

 

 

 -

Natural gas futures

 

 

0.1 

 

 

0.1 

 

 

 -

 

 

 -

Forward power contracts

 

 

11.2 

 

 

 -

 

 

11.2 

 

 

 -

Total Derivative liabilities

 

 

12.3 

 

 

0.5 

 

 

11.2 

 

 

0.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

 

882.5 

 

 

 -

 

 

864.3 

 

 

18.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liabilities

 

$

894.8 

 

$

0.5 

 

$

875.5 

 

$

18.8 

Assets and Liabilities at Fair Value
    Level 1 Level 2 Level 3
$ in millions Fair value at December 31, 2014 Based on Quoted Prices in Active Markets Other Observable Inputs Unobservable Inputs
Assets        
Master Trust assets        
Money market funds $0.1
 $0.1
 $—
 $—
Equity securities 3.7
 —
 3.7
 —
Debt securities 4.7
 —
 4.7
 —
Hedge funds 0.8
 —
 0.8
 —
Real estate 0.4
 —
 0.4
 —
Total Master Trust assets 9.7
 0.1
 9.6
 —
         
Derivative assets        
Forward power contracts 15.1
 —
 13.9
 1.2
Total Derivative assets 15.1
 —
 13.9
 1.2
         
Total assets $24.8
 $0.1
 $23.5
 $1.2
         
Liabilities        
Derivative liabilities        
FTRs $0.6
 $—
 $—
 $0.6
Heating oil futures 0.4
 0.4
 —
 —
Natural gas futures 0.1
 0.1
 —
 —
Forward power contracts 11.2
 —
 11.2
 —
Total Derivative liabilities 12.3
 0.5
 11.2
 0.6
         
Debt 882.5
 —
 864.3
 18.2
         
Total liabilities $894.8
 $0.5
 $875.5
 $18.8

Our financial instruments are valued using the market approach in the following categories:

·

Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents.  The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. 

·

Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market).  Other Level 2 assets include open-ended mutual funds that are in the Master Trust, which are valued using observable prices based on the end of day NAV per unit. 

Level 1 inputs are used for derivative contracts such as heating oil futures and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.

·

Level 3 inputs such as financial transmission rights are considered a Level 3 input because the monthly auctions are considered inactive.  Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented. 

Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include open-ended mutual funds that are in the Master Trust, which are valued using observable prices based on 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.
Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. Since the Wright-Patterson Air Force Base loan is not publicly traded, fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures are not presented since debt is not recorded at fair value.


Approximately 98%97% of the inputs to the fair value of our derivative instruments are from quoted market prices.

55




57

Table of Contents


Non-recurring FairFair 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. AROs for ash ponds, asbestos, river structures and underground storage tanks increased by $0.6a net amount of $38.7 million and $1.2 million during the threenine months ended March 31,September 30, 2015 and 2014, respectively 

8.respectively. The majority of the increase in 2015 is due to an increase in the AROs for ash ponds ($40.6 million) due to new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015.


Note 9 – Derivative Instruments and Hedging Activities


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


At March 31,September 30, 2015, DP&L had the following outstanding derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Accounting Treatment

 

Unit

 

Purchases
(in thousands)

 

Sales
(in thousands)

 

Net Purchases/ (Sales)
(in thousands)

FTRs

 

 

Mark to Market

 

MWh

 

 

4.2 

 

 

 -

 

 

4.2 

Heating oil futures

 

 

Mark to Market

 

Gallons

 

 

252.0 

 

 

 -

 

 

252.0 

Forward power contracts

 

 

Cash Flow Hedge

 

MWh

 

 

843.5 

 

 

(3,708.3)

 

 

(2,864.8)

Forward power contracts

 

 

Mark to Market

 

MWh

 

 

1,565.1 

 

 

(4,911.8)

 

 

(3,346.7)

Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Mark to Market MWh 24.7
 —
 24.7
Forward power contracts Cash Flow Hedge MWh 1,361.2
 (7,857.7) (6,496.5)
Forward power contracts Mark to Market MWh 5,309.7
 (1,916.5) 3,393.2

At December 31, 2014, DP&L had the following outstanding derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Accounting Treatment

 

Unit

 

Purchases
(in thousands)

 

Sales
(in thousands)

 

Net Purchases/ (Sales)
(in thousands)

FTRs

 

 

Mark to Market

 

MWh

 

 

10.5 

 

 

 -

 

 

10.5 

Heating oil futures

 

 

Mark to Market

 

Gallons

 

 

378.0 

 

 

 -

 

 

378.0 

Natural Gas

 

 

Mark to Market

 

Dths

 

 

200.0 

 

 

 -

 

 

200.0 

Forward power contracts

 

 

Cash Flow Hedge

 

MWh

 

 

175.0 

 

 

(2,991.0)

 

 

(2,816.0)

Forward power contracts

 

 

Mark to Market

 

MWh

 

 

1,725.2 

 

 

(2,804.0)

 

 

(1,078.8)

Commodity Accounting Treatment Unit 
Purchases
(in thousands)
 
Sales
(in thousands)
 
Net Purchases/ (Sales)
(in thousands)
FTRs Mark to Market MWh 10.5
 —
 10.5
Heating oil futures Mark to Market Gallons 378.0
 —
 378.0
Natural Gas Mark to Market Dths 200.0
 —
 200.0
Forward power contracts Cash Flow Hedge MWh 175.0
 (2,991.0) (2,816.0)
Forward power contracts Mark to Market MWh 1,725.2
 (2,804.0) (1,078.8)

Cash Flow Hedges

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


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

56




58

Table of Contents


The following tables providetable provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended March 31,September 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

Three months ended

 

 

March 31, 2015

 

March 31, 2014

 

 

 

 

Interest

 

 

 

Interest

$ in millions (net of tax)

 

Power

 

Rate Hedge

 

Power

 

Rate Hedge

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning accumulated derivative gain in AOCI

 

$

0.2 

 

$

2.6 

 

$

1.0 

 

$

5.2 

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

 

 

0.1 

 

 

 -

 

 

(12.9)

 

 

 -

Net gains / (losses) reclassified to earnings

Interest expense

 

 

 -

 

 

(0.2)

 

 

 -

 

 

(0.3)

Revenues

 

 

(0.2)

 

 

 -

 

 

6.6 

 

 

 -

Purchased power

 

 

0.9 

 

 

 -

 

 

(0.6)

 

 

 -

Ending accumulated derivative gain / (loss) in AOCI

 

$

1.0 

 

$

2.4 

 

$

(5.9)

 

$

4.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

Portion expected to be reclassified to earnings in the next twelve months (a)

 

$

1.1 

 

$

1.0 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

21 

 

 

0 

 

 

 

 

 

 

(a)

  Three months ended Three months ended
  September 30, 2015 September 30, 2014
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gain in AOCI $1.1
 $2.2
 $(14.0) $4.6
Net gains / (losses) associated with current period hedging transactions 7.8
 —
 1.4
 —
Net gains / (losses) reclassified to earnings        
Interest expense —
 (0.1) —
 (0.2)
Revenues (2.5) —
 3.2
 —
Purchased power 0.6
 —
 0.2
 —
Ending accumulated derivative gain / (loss) in AOCI $7.0
 $2.1
 $(9.2) $4.4

The actual amounts that we reclassify fromfollowing table provides information for DP&L concerning gains or losses recognized in AOCI to earnings related to power can differ fromfor the estimate above due to market price changes.cash flow hedges for the nine months ended September 30, 2015 and 2014:

  Nine months ended Nine months ended
  September 30, 2015 September 30, 2014
    Interest   Interest
$ in millions (net of tax) Power Rate Hedge Power Rate Hedge
Beginning accumulated derivative gain in AOCI $0.2
 $2.6
 $1.0
 $5.2
Net gains / (losses) associated with current period hedging transactions 9.6
 —
 (26.3) —
Net gains / (losses) reclassified to earnings        
Interest expense —
 (0.5) —
 (0.8)
Revenues (4.5) —
 16.6
 —
Purchased power 1.7
 —
 (0.5) —
Ending accumulated derivative gain / (loss) in AOCI $7.0
 $2.1
 $(9.2) $4.4
         
Portion expected to be reclassified to earnings in the next twelve months (a)
 $3.3
 $(0.8)    
         
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 39
 0
    

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

Mark to Market Accounting

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the Condensed Statements of 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 forwards, heating oil futures and certain forward power contracts are marked to market.


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



59
Table of Contents


Regulatory Assets and Liabilities

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

57


Table of Contents

The following tables present the amount and classification within the Condensed Statements of Operations or Condensed Balance Sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three and nine months ended March 31,September 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Heating Oil

 

FTRs

 

Power

 

Natural Gas

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized gain / (loss)

 

$

0.1 

 

$

0.9 

 

$

(2.9)

 

$

0.1 

 

$

(1.8)

Realized loss

 

 

(0.1)

 

 

(0.1)

 

 

(2.3)

 

 

(0.1)

 

 

(2.6)

Total

 

$

 -

 

$

0.8 

 

$

(5.2)

 

$

 -

 

$

(4.4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Recorded in Income Statement: gain / (loss)

 

 

 

Purchased power

 

 

 -

 

 

0.8 

 

 

(4.9)

 

 

 -

 

 

(4.1)

Revenues

 

 

 -

 

 

 -

 

 

(0.3)

 

 

 -

 

 

(0.3)

Total

 

$

 -

 

$

0.8 

 

$

(5.2)

 

$

 -

 

$

(4.4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended March 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended September 30, 2015For the three months ended September 30, 2015

$ in millions

 

Heating Oil

 

FTRs

 

Power

 

Total

 Heating Oil FTRs Power Total

 

 

 

 

 

 

 

 

 

 

 

 

Change in unrealized loss

 

$

(0.1)

 

$

(0.3)

 

$

(5.5)

 

$

(5.9)

Realized gain / (loss)

 

 

0.1 

 

 

 -

 

 

(1.4)

 

 

(1.3)
Change in unrealized gain / (loss) $0.1
 $0.1
 $(3.3) $(3.1)
Realized loss (0.2) (0.1) (4.3) (4.6)

Total

 

$

 -

 

$

(0.3)

 

$

(6.9)

 

$

(7.2)		 $(0.1) $—
 $(7.6) $(7.7)

 

 

 

 

 

 

 

 

 

 

 

 

Recorded in Income Statement: gain / (loss)

Recorded in Income Statement: gain / (loss)

Recorded in Income Statement: gain / (loss) 
Purchased power $—
 $—
 $(11.0) $(11.0)

Revenues

 

 

 -

 

 

 -

 

 

0.8 

 

 

0.8 		 —
 —
 3.4
 3.4

Purchased power

 

 

 -

 

 

(0.3)

 

 

(7.7)

 

 

(8.0)

Fuel

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 (0.1) —
 —
 (0.1)

Total

 

$

 -

 

$

(0.3)

 

$

(6.9)

 

$

(7.2)		 $(0.1) $—
 $(7.6) $(7.7)


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

For the nine months ended September 30, 2015
$ in millions Heating Oil FTRs Power Natural Gas Total
Change in unrealized gain / (loss) $0.4
 $0.2
 $(5.0) $0.1
 $(4.3)
Realized loss (0.3) (0.1) (8.1) (0.1) (8.6)
Total $0.1
 $0.1
 $(13.1) $—
 $(12.9)
Recorded on Balance Sheet:      
Regulatory Asset $0.1
 $—
 $—
 $—
 $0.1
           
Recorded in Income Statement: gain / (loss)  
Purchased power —
 0.1
 (21.9) —
 (21.8)
Revenues —
 —
 8.8
 —
 8.8
Total $0.1
 $0.1
 $(13.1) $—
 $(12.9)



60
Table of Contents

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

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.

58


Table of Contents

The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Values of Derivative Instruments

at March 31, 2015

 

 

 

 

 

 

 

 

Gross Amounts Not Offset in the Condensed Balance Sheets

 

 

 

$ in millions

 

Hedging Designation

 

Gross Fair Value as presented in the Condensed Balance Sheets

 

Financial Instruments with Same Counterparty in Offsetting Position

 

Cash Collateral

 

 

Net Balance Fair Value

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current assets)

Forward power contracts

 

Cash Flow

 

$

5.2 

 

$

(2.5)

 

$

 -

 

$

2.7 

Forward power contracts

 

MTM

 

 

5.0 

 

 

(3.2)

 

 

 -

 

 

1.8 

FTRs

 

MTM

 

 

0.3 

 

 

 -

 

 

 -

 

 

0.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred assets)

Forward power contracts

 

Cash Flow

 

 

3.8 

 

 

(2.7)

 

 

 -

 

 

1.1 

Forward power contracts

 

MTM

 

 

6.5 

 

 

(0.6)

 

 

 -

 

 

5.9 

Total assets

 

 

 

 

$

20.8 

 

$

(9.0)

 

$

 -

 

$

11.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current liabilities)

Forward power contracts

 

Cash Flow

 

$

4.1 

 

$

(2.5)

 

$

(1.6)

 

$

 -

Forward power contracts

 

MTM

 

 

13.1 

 

 

(3.2)

 

 

(8.8)

 

 

1.1 

Heating oil futures

 

MTM

 

 

0.3 

 

 

 -

 

 

(0.3)

 

 

 -

FTRs

 

MTM

 

 

 -

 

 

 -

 

 

 -

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred liabilities)

Forward power contracts

 

Cash Flow

 

 

2.7 

 

 

(2.7)

 

 

 -

 

 

 -

Forward power contracts

 

MTM

 

 

0.7 

 

 

(0.6)

 

 

 -

 

 

0.1 

Total liabilities

 

 

 

 

$

20.9 

 

$

(9.0)

 

$

(10.7)

 

$

1.2 

59

Table of Contents

The following table presents the fair value and balance sheet classification of DP&L’s derivative instruments at September 30, 2015:


Fair Values of Derivative Instruments
at September 30, 2015
      Gross Amounts Not Offset in the Condensed Balance Sheets  
$ in millions Hedging Designation Gross Fair Value as presented in the Condensed Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Balance Fair Value
Assets          
Short-term derivative positions (presented in Other current assets)
Forward power contracts Cash Flow $10.8
 $(6.0) $—
 $4.8
Forward power contracts MTM 5.4
 (4.0) —
 1.4
FTRs MTM 0.4
 (0.4) —
 —
           
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts Cash Flow 8.2
 (3.0) —
 5.2
Forward power contracts MTM 5.8
 (5.2) —
 0.6
Total assets   $30.6
 $(18.6) $—
 $12.0
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts Cash Flow $6.0
 $(6.0) $—
 $—
Forward power contracts MTM 9.0
 (4.0) (4.6) 0.4
FTRs MTM 0.7
 (0.4) —
 0.3
           
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts Cash Flow 3.0
 (3.0) —
 —
Forward power contracts MTM 6.5
 (5.2) (1.0) 0.3
Total liabilities   $25.2
 $(18.6) $(5.6) $1.0



61
Table of Contents

The following table presents the fair value and balance sheet classification of DPL’s derivative instruments at December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Values of Derivative Instruments

at December 31, 2014

 

 

 

 

 

 

 

 

Gross Amounts Not Offset in the Condensed Balance Sheets

 

 

 

$ in millions

 

Hedging Designation

 

Gross Fair Value as presented in the Condensed Balance Sheets

 

Financial Instruments with Same Counterparty in Offsetting Position

 

Cash Collateral

 

 

Net Balance Fair Value

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current assets)

Forward power contracts

 

Cash Flow

 

$

5.6 

 

$

(2.0)

 

$

 -

 

$

3.6 

Forward power contracts

 

MTM

 

 

5.6 

 

 

(3.4)

 

 

 -

 

 

2.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred assets)

Forward power contracts

 

Cash Flow

 

 

0.3 

 

 

(0.3)

 

 

 -

 

 

 -

Forward power contracts

 

MTM

 

 

3.6 

 

 

(0.9)

 

 

 -

 

 

2.7 

Total assets

 

 

 

 

$

15.1 

 

$

(6.6)

 

$

 -

 

$

8.5 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term derivative positions (presented in Other current liabilities)

Forward power contracts

 

Cash Flow

 

$

2.1 

 

$

(2.0)

 

$

 -

 

$

0.1 

Forward power contracts

 

MTM

 

 

7.5 

 

 

(3.4)

 

 

(4.1)

 

 

 -

FTRs

 

MTM

 

 

0.6 

 

 

 -

 

 

 -

 

 

0.6 

Heating oil futures

 

MTM

 

 

0.4 

 

 

 -

 

 

(0.4)

 

 

 -

Natural gas futures

 

MTM

 

 

0.1 

 

 

 -

 

 

(0.1)

 

 

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term derivative positions (presented in Other deferred liabilities)

Forward power contracts

 

Cash Flow

 

 

0.6 

 

 

(0.3)

 

 

(0.3)

 

 

 -

Forward power contracts

 

MTM

 

 

1.0 

 

 

(0.9)

 

 

 -

 

 

0.1 

Total liabilities

 

 

 

 

$

12.3 

 

$

(6.6)

 

$

(4.9)

 

$

0.8 

Fair Values of Derivative Instruments
at December 31, 2014
      Gross Amounts Not Offset in the Condensed Balance Sheets  
$ in millions Hedging Designation Gross Fair Value as presented in the Condensed Balance Sheets Financial Instruments with Same Counterparty in Offsetting Position Cash Collateral Net Balance Fair Value
Assets          
Short-term derivative positions (presented in Other current assets)
Forward power contracts Cash Flow $5.6
 $(2.0) $—
 $3.6
Forward power contracts MTM 5.6
 (3.4) —
 2.2
           
Long-term derivative positions (presented in Other deferred assets)
Forward power contracts Cash Flow 0.3
 (0.3) —
 —
Forward power contracts MTM 3.6
 (0.9) —
 2.7
Total assets   $15.1
 $(6.6) $—
 $8.5
           
Liabilities          
Short-term derivative positions (presented in Other current liabilities)
Forward power contracts Cash Flow $2.1
 $(2.0) $—
 $0.1
Forward power contracts MTM 7.5
 (3.4) (4.1) —
FTRs MTM 0.6
 —
 —
 0.6
Heating oil futures MTM 0.4
 —
 (0.4) —
Natural gas futures MTM 0.1
 —
 (0.1) —
           
Long-term derivative positions (presented in Other deferred liabilities)
Forward power contracts Cash Flow 0.6
 (0.3) (0.3) —
Forward power contracts MTM 1.0
 (0.9) —
 0.1
Total liabilities   $12.3
 $(6.6) $(4.9) $0.8

The aggregate fair value of DP&L’s commodity derivative instruments that were in a MTM loss position at March 31,September 30, 2015 was $20.9$25.2 million. $10.7$5.6 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 $9.0$18.6 million. Since our debt is below investment grade, we could be required to post collateral for the remaining $1.2$1.0 million.

9.


Note 10 – Shareholder’s Equity


DP&L has 250,000,000 authorized $0.01 par value common shares, of which 41,172,173 are outstanding at March 31,September 30, 2015. All common shares are held by DP&L’s parent, DPL.


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

60


Table of Contents

10.Note 11 – Contractual Obligations, Commercial Commitments and Contingencies

DP&L –


Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company, which is recorded using the cost method of accounting under GAAP. As of March 31,September 30, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.4$73.9 million, of a $1,519.3$1,507.9 million debt obligation that has maturities from 2018 to 2040.


62
Table of Contents

This would only happen if OVEC defaulted on its debt payments. As of March 31,September 30, 2015, 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, 2014.


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 Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31,September 30, 2015, cannot be reasonably determined.


Environmental Matters

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

·

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

·

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


·

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

The federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions,

·

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

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 climate change,

·

Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and

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

·

Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste.  The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products. 

Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require reporting and reductions of GHGs,

Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. At March 31,September 30, 2015, and December 31, 2014, we had accruals of approximately $0.8$0.7 million and $0.8 million, respectively, for environmental matters and other claims. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated, which are disclosed in the paragraphs below. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates.accruals. Such revisions in

61

Table of Contents

the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.


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

such EGUs and stations or our financial condition.


National Ambient Air Quality Standards

Effective August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO2 replacing the previous 24-hour standard and annual standard with a one-hour standard. Initial non-attainment designations were made July 25, 2013, and Pierce Township in Clermont County, location of DP&L’s co-owned unit Beckjord Unit 6, was the only area with DP&L operations designated as non-attainment.  Beckjord Unit 6 was retired effective October 1, 2014.  Non-attainment areas will be required to


63
Table of Contents

meet the 2010 standard by October 2018. On April 17, 2014,August 21, 2015, the USEPA proposedfinalized a data requirements rule for air agencies to ascertain attainment characterization more extensively across the country by additional modeling and/or monitoring requirements of areas with sources that exceed specified thresholds of SO2 emissions.emissions, which became effective on September 21, 2015. The rule if finalized,directs state agencies to provide data to characterize air quality in areas with sources of SO2 above 2,000 tons per year to identify maximum 1-hour concentrations of SO2 in ambient air. The rule could require the installation of monitors at one or more of DP&L’s coal-fired power plants and result in additional non-attainment designations that could impact our operations. On March 20, 2015, the USEPA informed environmental commissioners of 28 states, including Ohio, that certain areas within their states will be addressed in the next round of designations.  The areas will be included if they have monitors that have newly violated the standard, or have areas with a stationary source that had SO2 emissions greater than a specified level.  The designations are to be completed by July 2, 2016.  DP&L’s co-owned unit Zimmer meets the criteria for stationary sources. DP&L is unable to determine the effect of thesethe rule changes on its operations.

Carbon Dioxide


On October 1, 2015, the USEPA released a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. We are currently reviewing the rule and Other Greenhouse Gas Emissions

assessing the impact on our operations. We cannot at this time determine the impact of this rule, but it could be material.


Climate Change Legislation and Regulation
The USEPA issued proposed GHG emissionsOn October 23, 2015, the USEPA's final CO2 emission rules for existing power plants (called the Clean Power Plan) were published in the Federal Register with an effective date of December 22, 2015. Additionally, the final NSPS for CO2 emissions from new, modified and reconstructed generating unitsfossil-fuel-fired power plants were published in the Federal Register on June 2, 2014.  UnderOctober 23, 2015 and are effective immediately. The Clean Power Plan provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved by 2030. Prior to the proposed rules, calledrule's publication in the Federal Register, fifteen states, including Ohio, filed a petition in the U.S. Court of Appeals for the D.C. Circuit seeking a stay of the Clean Power Plan, which was denied by the Court in September 2015. On October 23, 2015, several states would be judged against state-specific CO2 emissions targets beginningand industry groups filed petitions in 2020, with an expected total U.S. power sector emissions reductionthe D.C. Circuit Court of 30% from 2005 levels by 2030.  For Ohio specifically,Appeals challenging the Clean Power Plan proposes an interim goalas published in the Federal Register, including a twenty-four state consortium that includes Ohio. The D.C. Circuit Court has issued orders consolidating the current pending challenges to the CPP under the lead case, West Virginia v. EPA. On October 23, 2015, North Dakota filed a petition for 2020-2029review of the GHG NSPS in the D.C. Circuit Court, and a proposed 2030 final goalcoalition of 1,452 poundsenvironmental groups have moved to intervene on behalf of CO2 per megawatt hourEPA in both the CPP and 1,338 poundsNSPS litigation. These state petitioners, as well as industry groups separately challenging the rule, have filed motions with the D.C. Circuit Court requesting a stay of CO2 per megawatt hour, respectively,the rule. The D.C. Circuit Court has issued orders consolidating the current pending challenges to the Clean Power Plan under the lead case, West Virginia v. USEPA. On October 23, 2015, North Dakota filed a reductionpetition for review of approximately 28% from 2012 levels.  The proposed rule requires states to submit implementation plans to meet the standards set forthCO2 NSPS in the D.C. Circuit Court, and a coalition of environmental groups have moved to intervene on behalf of USEPA in both the Clean Power Plan and NSPS litigation. Additional legal challenges are expected. We are currently reviewing the rule by June 30, 2016, withand assessing the possibilityimpact on our operations. Our business, financial condition or results of one- or two-year extensions under certain circumstances.  The state plans may focus on energy efficiency improvements at power stations, state renewable portfolio standards, re-dispatch to natural gas combined cycle units and other measures.  Weoperations could be required, among other things, to make efficiency improvements at our facilities.  USEPA expects to finalizematerially and adversely affected by this rule by August 1, 2015.  We cannot predict the effect of these proposed rules on rule.DP&L’s operations. 


Clean Water Act – Regulation of Water Discharge

In December 2006, DP&Lsubmitted a renewal application for the Stuart generating station NPDES permit that was due to expire on June 30, 2007. The Ohio EPA issued a draft permit that was received onin November 12, 2008. In September 2010, the USEPA formally objected to the November 12, 2008, draft permit due to questions regarding the basis for the alternate thermal limitation. The Ohio EPA issued a draft permit in December 2011 and a public hearing was held onin February 2, 2012. The draft permit required DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&Lsubmitted comments to the draft permit. In November 2012, the Ohio EPA issued another draft which included a compliance schedule for performing a study to justify an alternate thermal limitation and to which DP&L submitted comments. In December 2012, the USEPA formally withdrew their objection to the permit. On January 7, 2013, the Ohio EPA issued a final permit.

On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission. A hearing before the Commission is scheduledhas been rescheduled for August 2015.March 2016. Depending on the outcome of the appeal process, the effects on DP&L’s business, financial condition or results of operations could be material.


On September 30, 2015, the USEPA released its final rule regulating various wastewater streams from steam electric power plants. The regulations were published in the Federal Register on November 3, 2015. We are reviewing the the rule to assess the potential impact on our operations and our current or future NPDES permits.

Regulation of Waste Disposal

In September 2002, DP&Land other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other


64
Table of Contents

parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. On August 16, 2006, an Administrative Settlement Agreement and Order

62

Table of Contents

on Consent (“ASAOC”) for the site was executed and became effective among a group of PRPs, not including DP&L, and the USEPA. On August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio (the “District Court”) against DP&L and numerous other defendants alleging that DP&Land the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. On February 10, 2011, the District Court Judge dismissed claims against DP&Lthat related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The District Court Judge, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck directly to the landfill. Discovery, including depositions of past and present DP&Lemployees, was conducted in 2012. On February 8, 2013, the District Court Judge granted DP&L’s motion for summary judgment on statute of limitations grounds with respect to claims seeking a contribution toward the costs that are expected to be incurred by the PRP group in performing an RI/FS under the August 15, 2006 ASAOC. That summary judgment ruling was appealed on March 4, 2013, and on July 14, 2014, a three-judge panel of the U.S. Court of Appeals for the 6th6th Circuit affirmed the lower Court’s ruling and subsequently denied a request by the plaintiffsPRP group for rehearing. On November 14, 2014, the PRP group appealed the decision to the U.S. Supreme Court, but the writ of certiorari was denied by the Court on January 20, 2015. On April 5, 2013, the PRP group entered into a second ASAOC (the "2013 ASAOC") relating primarily to vapor intrusion from under some of the buildings at the South Dayton Dump landfill site. On April 13, 2013, as amended July 30, 2013, the PRP group filed another civil complaint against DP&L and numerous other defendants alleging that each defendant contributed to the contamination of the site by delivering hazardous waste to the site or by releasing hazardous waste on other sites that migrated to the landfill site. On February 18, 2014, after considering various motions and alternative grounds to dismiss, the District Court Judge dismissed some of the alleged grounds for relief that the PRP group had made, but ruled in the PRP group’s favor with respect to motions to dismiss the case in its entirety finding, among other things, that the 2013 ASAOC involved a different scope of work and thus the contributions sought were not seeking the same remedy that had been dismissed in the first civil suit. Appeals fromof this ruling are pending before the 6th6th Circuit Court of Appeals. On January 14, 2015, the PRP group served DP&L and other defendants a request for production of documents related to any survey regarding waste management or waste disposal.disposal surveys. Information responsive to this request was provided on February 17, 2015. In addition, on January 16, 2015, the USEPA issued a Special Notice Letter and Section 104(e) Information Request to DP&L and other defendants, requesting historical information related to waste management practices.practices that may be relevant to the site. DP&L responded to this request on March 27, 2015. In June 2015, DP&L was again requested to grant access to the DP&L service building property for the purpose of collecting groundwater samples from selected monitoring wells. DP&L granted access and groundwater sampling took place in June 2015. As a result of an August 11, 2015 meeting among the parties, the parties have agreed to stay the case in order to explore the possibility of a negotiated resolution of some or all of the issues.  DP&L is unable to predict the outcome of this actionthese actions by the plaintiffs and USEPA. Additionally, the District Court’s 2013 ruling and the Court of Appeals’ affirmation of that ruling in 2014 does not address future litigation that may arise with respect to actual remediation costs. While DP&L is unable to predict the outcome of these and any future matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its business, financial condition or results of operations.


Regulation of Ash Ponds

There has been increasing advocacy to regulate coal combustion residuals (CCR) under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA released its final rule onin December 19, 2014, designating coal combustion residuals that are not beneficially reused as non-hazardous solid waste under RCRA Subtitle D. The rule was published in the Federal Register onin April 17, 2015 and becomesbecame effective October 19, 2015, and applies new detailed management practices to new and existing landfills and surface impoundments, including lateral expansions of such units. DP&L is currently reviewingBased on our review of the rule, and assessing the impact onwe have adjusted our operations.  Our business, financial condition or operations could be materially and adversely affected by this regulation.    

AROs related to ash ponds (see Note 8), but we

63


65

Table of Contents


are currently unable to determine the full impact of the rule as it is contingent upon future activities required by the regulation.



66
Table of Contents

Item 2.  Management’s2 – Management's Discussion and Analysis of Financial Condition and Results of Operations


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


The following discussion contains forward-looking statements and should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes of DPLand the Condensed Financial Statements and related footnotes of DP&Lincluded in Part I – Financial Information, the risk factors in Item 1A to Part I of our Form 10-K for the fiscal year ending December 31, 2014 and in Item 1A to Part II of this Quarterly Report on Form 10-Q, and our “Forward-Looking Statements” section of this Form 10-Q. For a list of certain abbreviations or acronyms in this discussion, see the Glossary at the beginning of this Form 10-Q.


REGULATORY ENVIRONMENT


DPL’s,DP&L’s and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities in an effort to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. See Note 910 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 1011 of Notes to DP&L’s Condensed Financial Statements.


On October 30, 2015 DP&L publicly announced its intent to file an application to increase its distribution rates at the Public Utilities Commission of Ohio on November 30, 2015. DP&L plans to use 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.

COMPETITION AND PJM PRICING

RPM


Capacity Auction Price

The PJM RPM capacity base residual auction for the 2017/18 period cleared at a per megawatt price of $120/day for our RTO area. The per megawatt prices for the periods 2016/17, 2015/16 and 2014/15 were $59/day, $136/day and $126/day, respectively, based on previous auctions. FutureAs discussed below, a new Capacity Performance ("CP") program has been approved by the FERC, which will phase out RPM as of the 2018/19 period. During the phase-out period, the RPM auction results will be dependent not onlywere modified based on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resourcestransitional auctions that were conducted in the RPM capacity auctions.  The SSO retail costs and revenues are included in the RPM rider.  Therefore, increases in customer switching causes morethird quarter of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.2015. We cannot predict the outcome of future auctions or customer switching but based on actual results attained, we estimate that a hypothetical increase or decrease of $10/day in the capacity auction price would result in an annual impact to net income of approximately $6.4$7.0 million and $5.1$5.7 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

There are proposals from PJM pending before


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

The PJM CP base residual auction for the 2018/19 period cleared at a per megawatt price of $165/day for our RTO area. PJM also conducted CP transition auctions for the 2016/17 and 2017/18 periods to RPM and longer-term modifications that would phase-out RPM and replace it with a Capacity Performance (“CP”) program.  Becausegive market participants the changesoption to upgrade to the new CP product. The CP transition auction for the 2016/17 period cleared at a per megawatt price of $134/day and the auction for the 2017/18 period cleared at a per megawatt price of $152/day.



67
Table of Contents

As approved, the CP program offers the potential for higher capacity markets proposedrevenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours.” This linkage between non- or under-performance during certain specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net Cost of New Entry, which is a value computed by PJM are still being evaluated by the FERC, the FERC has approved a waiver that allows PJMPJM. This level is likely to delaybe larger than the capacity auctionprice established under the CP program, so that would have been heldthe potential exists that participation in May 2015.

the CP program could result in capacity penalties that exceed capacity revenues.


At present, DP&L is unable to project whether the CP program will be beneficial or negative to DP&L’s operations, but the results could be material to DP&L’s operations.

Ohio Competitive Considerations and Proceedings

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to supplyprovide retail generation service to customers that do not choose an alternative supplier; however;however, the supply of electricity for DP&L’s SSO customers is partially sourced through a competitive bid auction in 2014 and 2015, with 100% sourced through competitive bid starting January 2016. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

64


Table of Contents

The following tables provide a summary of the number of electric customers and volumes supplied by DPLER and non-affiliated CRES providers in our service territory during the three and nine months ended March 31,September 30, 2015 and 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

Three months ended

 

 

March 31, 2015

 

 

March 31, 2014

 

 

Electric Customers

 

Sales (in millions of kWh)

 

 

Electric Customers

 

Sales (in millions of kWh)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supplied by DPLER (a)

124,367 

 

 

1,149 

 

 

 

138,420 

 

 

1,604 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supplied by non-affiliated CRES providers

116,568 

 

 

1,413 

 

 

 

90,593 

 

 

999 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total in DP&L's service territory

240,935 

 

 

2,562 

 

 

 

229,013 

 

 

2,603 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution customers/sales by DP&L in our service territory (b)

516,324 

 

 

3,756 

 

 

 

515,748 

 

 

3,827 

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

(b)The volumes supplied by DPLER represent approximately 31% and 42%

 Three months endedThree months ended
 September 30, 2015September 30, 2014
 Electric Customers (a)Sales (in millions of kWh)Electric Customers (a)Sales (in millions of kWh)
Supplied by DPLER (b)112,726
991
134,703
1,366
     
Supplied by non-affiliated CRES providers124,625
1,656
102,337
1,181
     
Total in DP&L's service territory237,351
2,647
237,040
2,547
     
Distribution customers/sales by DP&L in our service territory (c)515,372
3,646
514,371
3,498

(a)Customers at the end of each period.    
(b)DPLER’s customer mix has shifted from high-volume industrial consumers to lower volume residential consumers.
(c)
The volumes supplied by DPLER represent approximately 27% and 39% of DP&L’s total distribution volumes during the three months ended September 30, 2015 and 2014, respectively. We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.


68
Table of DP&L’s total distribution volumes during the three months ended March 31, 2015 and 2014, respectively.  We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows. 

Contents


 Nine months endedNine months ended
 September 30, 2015September 30, 2014
 Electric Customers (a)Sales (in millions of kWh)Electric Customers (a)Sales (in millions of kWh)
Supplied by DPLER (b)112,726
3,094
134,703
4,366
     
Supplied by non-affiliated CRES providers124,625
4,525
102,337
3,183
     
Total in DP&L's service territory237,351
7,619
237,040
7,549
     
Distribution customers/sales by DP&L in our service territory (c)515,372
10,659
514,371
10,588

(a)Customers at the end of each period.    
(b)DPLER’s customer mix has shifted from high-volume industrial consumers to lower volume residential consumers.
(c)
The volumes supplied by DPLER represent approximately 29% and 41% of DP&L’s total distribution volumes during the nine months ended September 30, 2015 and 2014, respectively. We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

DPLER, an affiliated company and one of the registered CRES providers, markets competitive transmission and generation services to DP&L customers.


FUEL AND RELATED COSTS


Fuel and Commodity Prices

The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues affect mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. For the year ending December 31, 2015, we have substantially all our coal requirements under contract to meet our committed sales. We may not be able to hedge the entire exposure of our operations from commodity price volatility. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.


65


69

Table of Contents


RESULTS OF OPERATIONS – DPL


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


Income Statement Highlights – DPL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

March 31,

$ in millions

 

2015

 

2014

Revenues:

 

 

 

 

 

 

Retail

 

$

338.9 

 

$

373.6 

Wholesale

 

 

94.6 

 

 

49.4 

RTO revenues

 

 

19.2 

 

 

26.7 

RTO capacity revenues

 

 

39.1 

 

 

8.4 

Other revenues

 

 

2.8 

 

 

2.7 

Other mark-to-market losses

 

 

(0.1)

 

 

(0.5)

Total revenues

 

 

494.5 

 

 

460.3 

 

 

 

 

 

 

 

Cost of revenues:

 

 

 

 

 

 

Fuel costs

 

 

76.7 

 

 

90.1 

Gains from the sale of coal

 

 

(0.2)

 

 

(0.2)

Mark-to-market losses / (gains)

 

 

(0.1)

 

 

0.1 

Total fuel

 

 

76.4 

 

 

90.0 

 

 

 

 

 

 

 

Purchased power

 

 

126.2 

 

 

106.9 

RTO charges

 

 

33.1 

 

 

51.5 

RTO capacity charges

 

 

33.0 

 

 

9.9 

Mark-to-market losses

 

 

1.9 

 

 

5.8 

Total purchased power

 

 

194.2 

 

 

174.1 

 

 

 

 

 

 

 

Amortization of intangibles

 

 

 -

 

 

0.3 

 

 

 

 

 

 

 

Total cost of revenues

 

 

270.6 

 

 

264.4 

 

 

 

 

 

 

 

Gross margin (a)

 

$

223.9 

 

$

195.9 

 

 

 

 

 

 

 

Gross margin as a percentage of revenues

 

 

45% 

 

 

43% 

 

 

 

 

 

 

 

Operating income / (loss)

 

$

72.6 

 

$

(119.3)

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

66

  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
Revenues:        
Retail $279.7
 $351.9
 $878.5
 $1,044.9
Wholesale 76.2
 65.1
 226.7
 144.8
RTO revenues 18.3
 18.5
 53.8
 64.0
RTO capacity revenues 37.3
 41.2
 114.3
 68.5
Other revenues 2.6
 2.6
 8.3
 8.3
Other mark-to-market losses —
 (0.1) (0.1) (0.9)
Total revenues 414.1
 479.2
 1,281.5
 1,329.6
Cost of revenues:        
Fuel costs 72.1
 85.3
 203.2
 236.1
Gains from the sale of coal (0.5) (0.3) (0.7) (0.4)
Mark-to-market losses / (gains) (0.2) 0.1
 (0.3) 0.2
Total fuel 71.4
 85.1
 202.2
 235.9
         
Purchased power 82.4
 76.2
 281.9
 264.8
RTO charges 24.4
 37.6
 79.5
 125.7
RTO capacity charges 35.5
 37.9
 94.2
 68.5
Mark-to-market losses 3.1
 2.0
 4.6
 7.2
Total purchased power 145.4
 153.7
 460.2
 466.2
         
Amortization of intangibles —
 0.3
 —
 0.9
         
Total cost of revenues 216.8
 239.1
 662.4
 703.0
         
Gross margin (a)
 $197.3
 $240.1
 $619.1
 $626.6
         
Gross margin as a percentage of revenues 48% 50% 48% 47%
         
Operating income / (loss) $40.3
 $90.5
 $166.0
 $9.3

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



70

Table of Contents


DPL – Revenues

Retail customers, especially residential and commercial customers, consume more electricity onduring warmer and colder days.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

 

 

March 31,

 

 

2015

 

2014

 

 

 

 

 

 

 

Heating degree days (a)

 

 

3,241 

 

 

3,357 

Cooling degree days (a)

 

 

 -

 

 

 -


(a)Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business.  The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit.  For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees.  In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 65 degrees Fahrenheit. 

  Three Months Ended September 30, Nine months ended September 30,
  2015 2014 2015 2014
Heating degree days (a) 35
 81
 3,707
 3,902
Cooling degree days (a) 637
 576
 1,048
 968

(a)Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees. In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 65 degrees Fahrenheit.

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


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

Three months ended

March 31,

$ in millions

2015 vs. 2014

Retail

Rate

$

15.6 

Volume

(45.8)

Other miscellaneous

(4.5)

Total retail change

(34.7)

Wholesale

Rate

28.2 

Volume

17.0 

Total wholesale change

45.2 

RTO capacity & other

RTO capacity and other revenues

23.3 

Other

Unrealized MTM

0.4 

Total other revenue

0.4 

Total revenues change

$

34.2 

For

  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2015 v 2014 2015 v 2014
Retail    
Rate $(18.6) $(5.3)
Volume (53.1) (154.3)
Other miscellaneous (0.5) (6.8)
Total retail change (72.2) (166.4)
     
Wholesale    
Rate 0.4
 24.0
Volume 10.7
 57.9
Total wholesale change 11.1
 81.9
     
RTO capacity & other    
RTO capacity and other revenues (4.1) 35.6
     
Other    
Unrealized MTM 0.1
 0.8
Total other revenue 0.1
 0.8
     
Total revenues change $(65.1) $(48.1)



71
Table of Contents

During the three months ended March 31,September 30, 2015, Revenues increased $34.2decreased $65.1 million to $494.5$414.1 million from $460.3$479.2 million in the same period of the prior year. This increasedecrease was primarily the result of increased wholesale and

67

Tablethe sale of Contents

RTO capacity and other revenues,MC Squared on April 1, 2015, as well as lower retail revenue at DPLER due to the impact of customer switching. These decreases were partially offset by lower retail revenue.increased wholesale sales. The changes in the components of revenue are discussed below:

·

Retail revenues decreased $34.7 million primarily due to decreased volume driven by a loss of DPLER customers both within and outside of DP&L’s service territory, although DP&L continues to provide distribution service to all customers within its service territory.  Also contributing to the decrease is a 4% decrease in heating degree days compared to 2014 as well as lower retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate.  Partially offsetting these decreases are increased DP&L retail revenue due to recovery of previously deferred costs and increased DPLER average rates.    

·

Wholesale revenues increased $45.2 million as a result of a $28.2 million increase in wholesale price and a favorable $ 17.0 million volume variance. The year over year price increase is resulting from the impact of realized derivative losses in 2014 largely due to extreme weather during January of 2014.  The volume increase was driven by 60% of SSO load being served through the competitive bid process compared to 10% during 2014 allowing excess generation to be sold in the wholesale market.  This was partially offset by a 20% decrease in net generation from DP&L’s co-owned and operated plants primarily due to the 2014 sale of East Bend and closing of Beckjord as well as increased outages. 


·

RTO capacity and other revenues, consisting primarily of compensation for use

Retail revenues decreased $72.2 million primarily due to the sale of MC Squared on April 1, 2015, which had sales of $35.8 million in the three months ended September 30, 2014. In addition, volumes decreased due to a loss of DPLER customers both within and outside of DP&L’s service territory. DP&L continues to provide distribution service to all customers within its service territory. Also contributing to the decrease is lower retail revenue for DP&L's SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate and higher cost recoveries at DP&L in the prior year. These decreases were partially offset by an increase in retail sales volume due to weather as cooling degree days were 11% higher.DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $23.3 million compared to the same period in 2014.  This increase was primarily the result of a $30.7 million increase in revenues realized from PJM capacity auction offset by a $7.5 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.  The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013.    


Wholesale revenues increased $11.1 million, due to a $10.7 million volume increase, as 60% of DP&L's SSO load is now being served through the competitive bid process compared to 10% during 2014, allowing excess generation to be sold in the wholesale market. This was partially offset by net generation being lower by 17% due to the 2014 sale of East Bend, the closing of Beckjord and the impact of unplanned outages.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $4.1 million. This decrease was primarily the result of a $3.8 million decrease in revenues from the PJM capacity auction. Although the per megawatt capacity prices that became effective in June 2015 were $136/day, compared to $126/day in June 2014, the decrease is a result of the 2014 sale of East Bend and the closing of Beckjord, as well as lower commercial availability due to unplanned outages as noted above, which caused the overall capacity to be less.

During the nine months ended September 30, 2015, Revenues decreased $48.1 million to $1,281.5 million from $1,329.6 million in the same period of the prior year. This decrease was primarily the result of decreased retail revenues partially offset by increased wholesale and RTO capacity revenues. The changes in the components of revenue are discussed below:

Retail revenues decreased $166.4 million primarily due to the sale of MC Squared on April 1, 2015. MC Squared had sales of $64.6 million during the period after April 1, 2014 through September 30, 2014. In addition, volumes decreased driven by a loss of DPLER customers both within and outside of DP&L’s service territory. DP&L continues to provide distribution service to all customers within its service territory. Also contributing to the decrease is a 5% decrease in heating degree days compared to the same period in 2014, lower retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate and higher cost recoveries at DP&L in the prior year.

Wholesale revenues increased $81.9 million due to a $57.9 million increase in volume and a favorable price variance of $24.0 million. The increase in volume is primarily driven by 60% of DP&L's SSO load being served through the competitive bid process compared to 10% during 2014, allowing excess generation to be sold in the wholesale market. This was partially offset by a 15% decrease in net generation from DP&L’s co-owned and operated plants primarily due to the 2014 sale of East Bend, the closing of Beckjord, as well as increased unplanned outages. The year over year price increase is a result of the impact of realized derivative losses in 2014 largely due to extreme weather during January of 2014.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $35.6 million. This increase was primarily the result of a $45.8 million increase in revenues realized from the PJM capacity auction The per megawatt capacity prices that became effective in June 2015 were $136/day, compared to $126/day in June 2014 and $28/day in June 2013. This increase was offset by a $10.1 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.



72
Table of Contents

DPL – Cost of Revenues

For

During the three months ended March 31, 2015: 

·

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $13.6 million, or 15%, compared to the same period in 2014,  primarily due to a 20% decrease in internal generation at our plants offset by a 6% increase in average fuel cost per MWh. 

September 30, 2015, Cost of Revenues decreased $22.3 million, or 9%, compared to the same period in the prior year:

·

Net purchased power increased $20.1 million, or 12%, compared to the same period in 2014 due largely to a $24.7 million volume increase driven by increased power purchased to source our SSO load through the competitive bid process as well as decreased internal generation and increased RTO capacity charges of $23.1 million.  These increases were partially offset by an $18.4 million decrease in other RTO charges, a $5.4 million decrease due to lower average prices compared to 2014 and a $3.9 million decrease in net MTM losses.  RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013.  RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers.  We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.


68

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $13.7 million, or 16%, primarily due to a 17% decrease in internal generation at our plants, partially offset by a 2% increase in average fuel cost per MWh.

Net purchased power decreased $8.3 million, or 5%, primarily due to decreased other RTO charges of $13.2 million as a result of higher transmission and congestion charges incurred in 2014. In addition, RTO capacity charges decreased $2.4 million driven by our decreased load obligations for retail customers in 2015, partially offset by a $7.3 million PJM penalty accrual associated with low plant availability in 2015 and higher RTO capacity prices, as noted above. RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers. These RTO-related decreases were partially offset by a $6.2 million increase in purchased power due to a $10.7 million increase in price, partially offset by a $4.5 million decrease in volume attributable to decreased power purchased to sell to DPLER, as a result of the sale of MC Squared and decreased customers in 2015 compared to the same period in 2014, partially offset by volume increases driven by increased power purchased to source our SSO load through the competitive bid process. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.

For the nine months ended September 30, 2015, Cost of Revenues decreased $40.6 million, or 6%, compared to the same period in the prior year:

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $33.7 million, or 14%, primarily due to a 15% decrease in internal generation at our plants partially offset by a 2% increase in average fuel cost per MWh.

Net purchased power decreased $6.0 million, or 1%, due to a $46.2 million decrease in other RTO charges and a $2.6 million decrease in net MTM losses. These decreases were partially offset by a $17.1 million increase in purchased power, due to an $18.8 million price increase, partially offset by a $1.7 million volume decrease attributable to decreased power purchased to sell to DPLER, as a result of the sale of MC Squared and decreased customers in 2015 compared to the same period in 2014, partially offset by volume increases driven by increased power purchased to source our SSO load through the competitive bid process. In addition, there were increased RTO capacity charges of $25.7 million driven by a $7.3 million PJM penalty associated with low plant availability in 2015 and higher RTO capacity prices, partially offset by a decreased load obligations for retail customers in 2015. As noted above, RTO capacity prices are set by an annual auction. RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.



73

Table of Contents


DPL – Operation and Maintenance

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

  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2015 v 2014 2015 v 2014
     
Low-income payment program (a)
 $(4.4) $(14.9)
Competitive retail operations (1.2) (7.7)
Alternative energy and energy efficiency programs (a)
 3.5
 0.5
Retirement benefits 0.3
 (2.1)
Maintenance of overhead transmission and distribution lines 2.4
 (2.9)
Deferred storm costs (a)
 4.4
 13.1
Other, net 2.4
 0.8
Total change in operation and maintenance expense $7.4
 $(13.2)

(a)

Three months ended

March 31,

$There is a corresponding offset in millions

2015 vs. 2014

Low-income payment program (a)

$

(6.1)

Competitive retail operations

(2.6)

Alternative energy and energy efficiency programs (a)

(2.2)

Health Insurance

(1.0)

Other, net

(1.1)

Total change in operation and maintenance expense

$

(13.0)

Revenues associated with these programs.

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

During the three months ended March 31,September 30, 2015, Operation and maintenance expense decreased $13.0increased $7.4 million, compared to the same period in the prior year. This variance was primarily the result of:

·

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

·

decreased marketing, customer maintenance and labor costs associated with the competitive retail business,

increased expenses for the alternative energy and energy efficiency programs,

·

decreased expenses relating to alternative energy and energy efficiency programs, and

increased costs associated with our retirement benefit plans,

·

decreased health insurance due to cost decreases. 

DPL – Depreciationincreased maintenance of overhead transmission and Amortization 

Fordistribution lines primarily due to storms in the threethird quarter of 2015, and

increased storm costs, which were previously deferred but are now being recognized as they are recovered through customer rates.

These decreases were partially offset by:
decreased expenses for the low-income payment program which is funded by the USF revenue rate rider, and
decreased marketing, customer maintenance and labor costs associated with the competitive retail business.

During the nine months ended March 31,September 30, 2015, DepreciationOperation and amortizationmaintenance expense decreased $0.3$13.2 million, compared to the same period in the prior year as ayear. This variance was primarily the result of an adjustment of $1.2 million to the AROsof:
decreased expenses for the Hutchings plantlow-income payment program which is funded by the USF revenue rate rider,
decreased marketing, customer maintenance and labor costs associated with the competitive retail business,
decreased costs associated with our retirement benefit plans, and
decreased maintenance of overhead transmission and distribution lines primarily due to storms in 2014the first quarter of 2014.

These decreases were partially offset by routine plant additionsby:

increased expenses for the alternative energy and replacements. 

energy efficiency programs, and

increased storm costs, which were previously deferred but are now being recognized as they are recovered through customer rates.
increased expenses for the alternative energy and energy efficiency programs.

DPL – General Taxes 

Depreciation and Amortization

For the three months ended March 31,September 30, 2015, Depreciation and amortization expense did not change significantly from the same period in the prior year. Depreciation expense decreased due to the sale of the East Bend Plant and the retirement of the Beckjord Plant; this decrease was offset by increased depreciation associated with increased ARO assets and net plant additions.



74
Table of Contents

For the nine months ended September 30, 2015, Depreciation and amortization expense did not change significantly from the same period in the prior year. Depreciation expense decreased due to the sale of the East Bend Plant and the retirement of the Beckjord Plant; this decrease was offset by increased depreciation associated with increased ARO assets and net plant additions.

DPL – General Taxes
For the three months ended September 30, 2015, General taxes did not change significantly from the same period in the prior year.

For the nine months ended September 30, 2015, General taxes decreased $3.5$2.5 million compared to the same period in the prior year. The decrease was primarily due to a 2014 adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments made in 2014 partially offset by higher property tax accruals for 2015 compared to 2014.


DPL – Interest Expense

Interest expense recorded during the three months ended March 31,September 30, 2015 decreased $0.3$4.2 million compared to the same period in the prior year. This was primarily driven by debt prepayments and the refinancing of certain debt.

Interest expense during the nine months ended September 30, 2015 decreased bond interest of $1.3$5.5 million as a result ofcompared to the same period in the prior year. This was primarily driven by debt prepayments and the refinancing of certain debt, partially offset by an increase related to the recovery of previously deferred carrying costs on regulatory assets of $1.1$1.3 million.


DPL – Income Tax Expense

For the three and nine months ended March 31,September 30, 2015, Income tax expense increased $41.3 million and decreased $86.1$16.2 million, respectively, compared to the same periodperiods in 2014,the prior year, primarily due to the application of an estimated annual Effective Tax Rate (ETR) approach in accordance with ASC 740-270, Interim Reporting. The ETR for 2015 is estimated to be 31.1%30.8% as compared to the estimated ETR applied to the prior year period of (65.8)(42.3)%. The primary factor impacting the 2014 ETR was the non-deductible goodwill impairment recorded in the first quarter of 2014.

69

Table There were several adjustments recorded in 2015 that also contributed to the overall decrease in tax expense in the nine month period, the most significant of Contentswhich were the tax effects due to the sale of MC Squared of $5.6 million and an anticipated refund of $2.2 million from the IRS for the filing of an amended 2011 predecessor tax return for the inclusion of the domestic manufacturing deduction.


RESULTS OF OPERATIONS BY SEGMENT – DPL


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


Utility Segment

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and distribute electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired power plants and distributes electricity to more than 516,000515,000 retail customers who are located in a 6,000 square mile area of west central Ohio. During 2015, DP&Lis required to source 60% of the generation for its SSO customers through a competitive bid process, followed by 100% beginning in 2016. By PUCO order, DP&L is required to divest its generation assets by January 1, 2017. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.


Competitive Retail Segment

The Competitive Retail segment iswas comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. On April 1, 2015, DPLER closed on the sale of MC Squared. MC Squared, to Chicago based Wolverine.a Chicago-based retail electricity supplier, served more than 116,000 customers in Northern Illinois while it was owned by DPLER. As of March 31,September 30, 2015, the Competitive Retail segment sold electricity to approximately 259,000128,000 customers currently located throughout Ohio and Illinois.  MC Squared, a Chicago-based retail electricity supplier, serves more than 116,000 customers in Northern Illinois.  After considering the sale of MC Squared on April 1, 2015, the Competitive Retail segment sold electricity to 143,000 customers.Ohio. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.


75
Table of Contents

DP&L sells power to DPLER and sold power to MC Squared under wholesale agreements. Under these agreements, intercompany sales from DP&L to DPLER and(and previously to MC SquaredSquared) are based on fixed-price contracts for each DPLER or MC Squared customer.contract. The price approximates market prices for wholesale power at the inception of each customer’s contract.  The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.


Other

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


Management primarily evaluates segment performance based on gross margin.


See Note 1011 of Notes to DPL’s Condensed Consolidated Financial Statements for further discussion of DPL’s reportable segments.


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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

 

 

 

 

 

 

 

March 31,

 

Increase /

 

 

 

 

 

2015

 

 

2014

 

(Decrease)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utility

 

 

 

 

$

202.3 

 

 

$

179.8 

 

$

22.5 

 

Competitive Retail

 

 

 

 

 

10.6 

 

 

 

8.2 

 

 

2.4 

 

Other

 

 

 

 

 

11.9 

 

 

 

8.8 

 

 

3.1 

 

Adjustments and eliminations

 

 

 

 

 

(0.9)

 

 

 

(0.9)

 

 

 -

 

Total consolidated

 

 

 

 

$

223.9 

 

 

$

195.9 

 

$

28.0 

 

  Three months ended  
  September 30, Increase /
  2015 2014 (Decrease)
Utility $177.7
 $218.0
 $(40.3)
Competitive Retail 10.4
 12.6
 (2.2)
Other 10.0
 10.3
 (0.3)
Adjustments and eliminations (0.8) (0.8) —
Total consolidated $197.3
 $240.1
 $(42.8)
  Nine months ended  
  September 30, Increase /
  2015 2014 (Decrease)
Utility $561.4
 $567.8
 $(6.4)
Competitive Retail 27.5
 34.9
 (7.4)
Other 32.7
 26.4
 6.3
Adjustments and eliminations (2.5) (2.5) —
Total consolidated $619.1
 $626.6
 $(7.5)

The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects, and for both periods presented, to those of DP&Lwhich are included in this Form 10-Q. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment

70

Table of Contents

would enhance an understanding of this business since these discussions are already included under the DP&L discussions following.




76
Table of Contents

Income Statement Highlights – Competitive Retail Segment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

 

 

 

 

 

 

 

March 31,

 

Increase /

$ in millions

 

 

 

 

2015

 

 

2014

 

(Decrease)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail

 

 

 

 

$

121.8 

 

 

$

148.9 

 

$

(27.1)

 

RTO and other

 

 

 

 

 

0.5 

 

 

 

(0.5)

 

 

1.0 

 

Total revenues

 

 

 

 

 

122.3 

 

 

 

148.4 

 

 

(26.1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased power

 

 

 

 

 

111.7 

 

 

 

140.2 

 

 

(28.5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross margins (a)

 

 

 

 

 

10.6 

 

 

 

8.2 

 

 

2.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operation and maintenance expense

 

 

 

 

 

6.7 

 

 

 

9.4 

 

 

(2.7)

 

Other expenses

 

 

 

 

 

1.0 

 

 

 

0.9 

 

 

0.1 

 

Total expenses

 

 

 

 

 

7.7 

 

 

 

10.3 

 

 

(2.6)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings before income tax

 

 

 

 

 

2.9 

 

 

 

(2.1)

 

 

5.0 

 

Income tax expense

 

 

 

 

 

1.3 

 

 

 

(0.7)

 

 

2.0 

 

Net income

 

 

 

 

$

1.6 

 

 

$

(1.4)

 

$

3.0 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross margin as a percentage of revenues

 

 

 

 

 

9%

 

 

 

6%

 

 

 

 

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

  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2015 2014 2015 2014
Revenues:        
Retail $77.0
 $140.7
 $273.6
 $414.9
RTO and other —
 0.6
 0.9
 —
Total revenues 77.0
 141.3
 274.5
 414.9
Cost of revenues:        
Purchased power 66.6
 128.7
 247.0
 380.0
         
Gross margin (a)
 10.4
 12.6
 27.5
 34.9
         
Operation and maintenance expense 6.0
 7.2
 18.3
 26.0
Other expense / (income) 0.2
 0.9
 0.9
 2.6
Total expenses 6.2
 8.1
 19.2
 28.6
         
Earnings before income tax 4.2
 4.5
 8.3
 6.3
Income tax expense / (benefit) 1.6
 1.5
 (2.6) 2.1
Net income $2.6
 $3.0
 $10.9
 $4.2
         
Gross margin as a percentage of revenues 14% 9% 10% 8%

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

Competitive Retail Segment – Revenue

For the three months ended March 31,September 30, 2015, the segment’s retail revenues decreased $26.1$64.3 million, or 18%46%, compared to the same period in the prior year, primarily due to the sale of MC Squared on April 1, 2015, which had sales of $35.8 million in the three months ended September 30, 2014, as well as decreased customer contract renewals in Ohio markets. The Competitive Retail segment sold approximately 1,391 million kWh of power to approximately 128,000 customers for the three months ended September 30, 2015 compared to approximately 2,498 million kWh (which included 571 million kWh for MC Squared) of power to more than 274,000 customers (which included approximately 117,000 MC Squared customers) during the same period of the prior year.  The decrease was

For the nine months ended September 30, 2015, the segment’s retail revenues decreased $140.4 million, or 34%, compared to the same period in the prior year, primarily due to decreased customer contract renewals in bothOhio and the Illinois and Ohio markets combined withsale of MC Squared on April 1, 2015, which had sales of $64.5 million in the six months ended September 30, 2014. In addition there were weather related volume decreases. The Competitive Retail segment sold approximately 2,0484,762 million kWh (which included 500 million kWh for MC Squared) of power to approximately 259,000128,000 customers for the threenine months ended March 31,September 30, 2015 compared to approximately 2,7827,614 million kWh (which included 1,728 million kWh for MC Squared) of power to more than 322,000274,000 customers (which included approximately 117,000 MC Squared customers) customers during the same period of the prior year.


Competitive Retail Segment – Purchased Power

For the three months ended March 31,September 30, 2015, the segment’s purchased power decreased $28.5$62.1 million, or 20%48%, compared to the same period in 2014the prior year primarily due to decreased purchased power volumes required to meet customer requirements, partially offset by higher average prices.the sale of MC Squared and a loss of DPLER customers both within and outside of DP&L’s service territory. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L.

Competitive Retail Segment – Operation and Maintenance


For the threenine months ended March 31, 2015, DPLER’s operation and maintenance expenses decreased as a result of decreased sales volume. 

Competitive Retail Segment – Income Tax Expense

For the three months ended March 31,September 30, 2015, the segment’s income tax expense increasedpurchased power decreased $133.0 million, or 35%, compared to the same period in the prior year primarily due to the sale of MC Squared.




77
Table of Contents

Competitive Retail Segment – Operation and Maintenance
For both the three and nine months ended September 30, 2015, DPLER’s operation and maintenance expenses decreased compared to the same period in the prior year, primarily due to decreased marketing and sales expense, as well as the sale of MC Squared.


Competitive Retail Segment – Income Tax Expense
For the three months ended sep, the segment's income tax expense did not change significantly from the same period in the prior year.

For the nine months ended September 30, 2015, the segment’s income tax expense decreased $4.7 million compared to the same period in the prior year primarily due to the discrete adjustment for the sale of MC Squared in the amount of $5.6 million. This decrease is partially offset by an increase to expense due to higher pre-tax income.

71




78

Table of Contents


RESULTS OF OPERATIONS – DP&L


Income Statement Highlights – DP&L

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended

 

 

March 31,

$ in millions

 

2015

 

2014

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

Retail

 

$

218.0 

 

$

225.4 

Wholesale

 

 

192.7 

 

 

175.7 

RTO revenues

 

 

18.3 

 

 

24.0 

RTO capacity revenues

 

 

32.3 

 

 

7.0 

Total revenues

 

 

461.3 

 

 

432.1 

 

 

 

 

 

 

 

Cost of revenues:

 

 

 

 

 

 

Fuel costs

 

 

69.6 

 

 

84.4 

Gains from the sale of coal

 

 

(0.2)

 

 

(0.2)

Mark-to-market losses / (gains)

 

 

(0.1)

 

 

0.1 

Total fuel

 

 

69.3 

 

 

84.3 

 

 

 

 

 

 

 

Purchased power

 

 

125.2 

 

 

104.5 

RTO charges

 

 

29.9 

 

 

48.0 

RTO capacity charges

 

 

32.7 

 

 

9.8 

Mark-to-market losses

 

 

1.9 

 

 

5.7 

Total purchased power

 

 

189.7 

 

 

168.0 

 

 

 

 

 

 

 

Total cost of revenues

 

 

259.0 

 

 

252.3 

 

 

 

 

 

 

 

Gross margin (a)

 

$

202.3 

 

$

179.8 

 

 

 

 

 

 

 

Gross margin as a percentage of

 

 

 

 

 

 

revenues

 

 

44% 

 

 

42% 

 

 

 

 

 

 

 

Operating Income

 

$

60.3 

 

$

21.3 

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

  Three months ended
September 30,		 Nine months ended
September 30,
$ in millions 2015 2014 2015 2014
Revenues:        
Retail $203.6
 $212.2
 $607.5
 $632.5
Wholesale 138.9
 191.0
 451.4
 502.8
RTO revenues 16.4
 17.8
 50.3
 60.1
RTO capacity revenues 30.3
 34.1
 93.4
 56.8
Other mark-to-market gains —
 (0.2) —
 0.3
Total revenues 389.2
 454.9
 1,202.6
 1,252.5
Cost of revenues:        
Fuel costs 69.7
 84.7
 189.9
 227.6
Gains from the sale of coal (0.5) (0.3) (0.7) (0.4)
Mark-to-market losses / (gains) (0.2) 0.1
 (0.3) 0.2
Total fuel 69.0
 84.5
 188.9
 227.4
         
Purchased power 82.1
 75.3
 280.5
 260.2
RTO charges 24.0
 37.5
 75.8
 122.0
RTO capacity charges 33.4
 37.4
 91.4
 67.9
Mark-to-market losses 3.0
 2.2
 4.6
 7.2
Total purchased power 142.5
 152.4
 452.3
 457.3
         
Total cost of revenues 211.5
 236.9
 641.2
 684.7
         
Gross margin (a)
 $177.7
 $218.0
 $561.4
 $567.8
         
Gross margin as a percentage of revenues 46% 48% 47% 45%
         
Operating Income $28.5
 $75.5
 $130.9
 $126.6

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

DP&L – Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore,DP&L’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. SinceDP&L plans to utilize its internal generating capacity to supply its retail customers’ needs first, increases in retail demand will decrease the volume of internal generation available to be sold in the wholesale market and vice versa.


The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impactingDP&L’s wholesale sales volume each hour throughout the year include: wholesale market prices,DP&L’s retail demand and retail demand elsewhere throughout the entire wholesale market area,DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities that are not being utilized to meet its retail demand.

72




79

Table of Contents


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

Three months ended

March 31,

$ in millions

2015 vs. 2014

Retail

Rate

$

  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2015 v 2014 2015 v 2014
Retail    
Rate $(17.3) $(18.4)
Volume 9.1
 1.0
Other miscellaneous (0.4) (7.6)
Total retail change (8.6) (25.0)
     
Wholesale    
Rate (12.6) 15.4
Volume (39.5) (66.8)
Total wholesale change (52.1) (51.4)
     
RTO capacity & other    
RTO capacity and other revenues (5.0) 26.5
     
Total revenues change $(65.7) $(49.9)

4.1 

Volume

(6.5)

Other miscellaneous

(5.0)

Total retail change

(7.4)

Wholesale

Rate

30.5 

Volume

(13.5)

Total wholesale change

17.0 

RTO capacity & other

RTO capacity and other revenues

19.6 

Total revenues change

$

29.2 

For the three months ended March 31,September 30, 2015, Revenues increased $29.2decreased $65.7 million to $461.3$389.2 million from $432.1$454.9 million in the same period in the prior year. The changes in the components of revenue are discussed below:

·

Retail revenues decreased $7.4 million as a result of decreased volume due to a 4% decrease in heating degree days compared to 2014 and also due to customer switching.  Also contributing to the decrease is lower retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate.  Partially offsetting these decreases are increased DP&L retail revenue due to recovery of previously deferred costs.

·

Wholesale revenues increased $17.0 million as a result of a $30.5 million increase in wholesale prices partially offset by a $13.5 million volume variance. The year over year price increase is resulting from the impact of realized derivative losses in 2014 largely due to extreme weather during January of 2014.  The volume decrease was driven by decreased intercompany sales to DPLER and a 21% decrease in net generation from DP&L’s co-owned and operated plants primarily due to the 2014 sale of East Bend and the closing of Beckjord as well as increased outages, partially offset by increased sales resulting from 60% of SSO load being served through the competitive bid process compared to 10% during 2014 allowing excess generation to be sold in the wholesale market.    


·

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $19.6 million compared to the same period in 2014.  This increase was primarily the result of a $25.2 million increase in revenues realized from the PJM capacityRetail revenues decreased $8.6 million as a result of a price decrease of $17.3 million due to higher recovery of transmission costs in the prior year and a decrease in the 2015 USF program recovery rate combined with lower retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015. The overall price decrease was partially offset by a volume increase of $9.1 million driven by a $5.7 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.  The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013.  


Wholesale revenues decreased $52.1 million, $39.5 million primarily due to a decrease in volume driven by decreased intercompany sales to DPLER, as a result of the sale of MC Squared and decreased customers in 2015 compared to the same period in 2014 and an 18% decrease in net generation from DP&L’s co-owned and operated plants due to the 2014 sale of East Bend, the closing of Beckjord and increased unplanned outages. These decreases were partially offset by increased sales resulting from 60% of SSO load being served through the competitive bid process compared to 10% during 2014 allowing excess generation to be sold in the wholesale market. In addition, there was a $12.6 million decrease due to price.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $5.0 million. This decrease was primarily the result of a $3.8 million decrease in revenues from the PJM capacity auction due to lower overall capacity as a result of the 2014 sale of East Bend and the closing of Beckjord, as well as lower commercial availability due to unplanned outages as noted above. This was partially offset by increased capacity prices as the per megawatt capacity prices that became effective in June 2015 were $136/day, compared to $126/day in June 2014.
For the nine months ended September 30, 2015, Revenues decreased $49.9 million to $1,202.6 million from $1,252.5 million in the same period in the prior year. The changes in the components of revenue are discussed below:

Retail revenues decreased $25.0 million primarily due to lower retail prices due to higher recovery of transmission costs in the prior year and a decrease in the 2015 USF program recovery rate combined with decreased retail revenue for SSO customers as the competitive auction rate, which represents 60% of our


80
Table of Contents

SSO load in 2015 compared to 10% in 2014, is lower than our non-auction generation rate. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015.

Wholesale revenues decreased $51.4 million due to a $66.8 million decrease in volume, partially offset by a favorable price variance of $15.4 million. The decrease in volume is driven by decreased intercompany sales to DPLER and a 17% decrease in net generation from DP&L’s co-owned and operated plants primarily due to the 2014 sale of East Bend and the closing of Beckjord as well as increased unplanned outages, partially offset by increased sales resulting from 60% of SSO load being served through the competitive bid process compared to 10% during 2014 allowing excess generation to be sold in the wholesale market. The year over year price increase is a result of the impact of realized derivative losses in 2014 largely due to extreme weather during January 0f 2014.

RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $26.5 million. This increase was primarily the result of a $36.6 million increase in revenues realized from the PJM capacity auction offset by a $9.8 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather. The per megawatt capacity prices for the PJM base residual auction for the 2015-2016 delivery year that became effective in June of 2015 were $136/day, compared to $126/day in June of 2014 and $28/day per day in June of 2013.

DP&L – Cost of Revenues

For the three months ended March 31, 2015: 

·

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $15.0 million, or 18%, compared to the same period in 2014, primarily due to a 21% decrease in internal generation at our plants partially offset by a 5% increase in average fuel cost per MWh.

September 30, 2015, Cost of Revenues decreased $25.4 million, or 11%, compared to the same period in the prior year:

·

Net purchased power increased $21.7 million, or 13%, compared to the same period in 2014 due largely to a $24.0 million volume increase driven by increased power purchased to source our SSO load through the competitive bid process as well as decreased internal generation and increased RTO capacity charges of $22.9 million.  These increases were partially offset by an $18.1 million decrease in other RTO charges, a $3.3 million decrease due to lower average prices compared to 2014 and a $3.8

Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $15.5 million, or 18%, primarily due to an 18% decrease in internal generation at our plants.
Net purchased power decreased $9.9 million, or 6%, due largely to a $4.3 million volume decrease attributable to decreased power purchased to sell to DPLER, as a result of the sale of MC Squared and decreased customers in 2015 compared to the same period in the prior year, partially offset by volume increases driven by increased power purchased to source our SSO load through the competitive bid process. In addition, other RTO charges decreased $13.5 million and RTO capacity charges decreased $4.0 million driven by our decreased load obligations for retail customers in 2015, partially offset by a $7.3 million PJM penalty accrual associated with low plant availability in 2015 and higher RTO capacity prices. These decreases were partially offset by an $11.1 million increase due to higher average prices compared to the same period in 2014 and a slight increase in net MTM losses. As noted above, RTO capacity prices are set by an annual auction. RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.

For the nine months ended September 30, 2015, Cost of Revenues decreased $43.5 million, or 6%, compared to the same period in the prior year:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $38.5 million, or 17%, primarily due to a 17% decrease in internal generation at our plants.
Net purchased power decreased $5.0 million, or 1%, due largely to a $46.2 million decrease in other RTO charges and a $2.6 million decrease in net MTM losses. These decreases were partially offset by a $20.3 million increase in purchased power, due to a $21.9 million price increase, partially offset by a $1.6 million volume decrease, and increased RTO capacity charges of $23.5 million driven by a $7.3 million PJM penalty accrual associated with low plant availability in 2015 and higher RTO capacity prices, partially offset by decreased load obligations for retail customers in 2015. As noted above, RTO capacity prices are set by an annual auction. RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to


81

73

Table of Contents

million decrease in net MTM losses.  RTO capacity prices are set by an annual auction. The capacity prices that became effective in June 2014 were $126/MWh, compared to $28/MWh in June 2013.  RTO charges are incurred as a member of PJM and include costs associated with our load obligations for retail customers.  We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.


planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.

DP&L – Operation and Maintenance

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

  Three months ended Nine months ended
  September 30, September 30,
$ in millions 2015 v 2014 2015 v 2014
     
Low-income payment program (a)
 $(4.4) $(14.9)
Alternative energy and energy efficiency programs (a)
 3.5
 0.5
Retirement benefits 0.5
 (1.5)
Maintenance of overhead transmission and distribution lines 2.4
 (2.9)
Deferred storm costs (a)
 4.4
 13.1
Other, net 2.2
 1.4
Total change in operation and maintenance expense $8.6
 $(4.3)

(a)

Three months ended

March 31,

$There is a corresponding offset in millions

2015 vs. 2014

Low-income payment program (a)

$

(6.1)

Generating facilities operations and maintenance expense

(2.8)

Alternative energy and energy efficiency programs (a)

(2.2)

Other, net

(0.4)

Total change in operation and maintenance expense

$

(11.5)

Revenues associated with these programs.

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

For the three months ended March 31,September 30, 2015, Operation and maintenance expense decreased $11.5increased $8.6 million, compared to the same period in the prior year. This variance was primarily the result of:

·

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

·

decreased expenses relating to alternative energy and energy efficiency programs, and


·

decreased maintenance expenses at our generating facilities.

increased expenses for the alternative energy and energy efficiency programs,

increased costs associated with our retirement benefits plan,
increased maintenance of overhead transmission and distribution lines primarily due to storms in the third quarter of 2015, and
increased storm costs, which were previously deferred but are now being recognized as they are recovered through customer rates.

These increases were partially offset by:
decreased expenses for the low-income payment program which is funded by the USF revenue rate rider.

For the nine months ended September 30, 2015, Operation and maintenance expense decreased $4.3 million, compared to the same period in the prior year. This variance was primarily the result of:

decreased expenses for the low-income payment program which is funded by the USF revenue rate rider,
decreased costs associated with our retirement benefits plan,
and decreased maintenance of overhead transmission and distribution lines primarily due to storms in the first quarter of 2014.

These decreases were partially offset by:
increased expenses for the alternative energy and energy efficiency programs, and
increased storm costs, which were previously deferred but are now being recognized as they are recovered through customer rates.

DP&L – Depreciation and Amortization

For the three months ended March 31,September 30, 2015, Depreciation and amortization expense decreased $1.8 million compared to the same period in the prior year as a result of an adjustment of $0.6 million in the AROs for the Hutchings plant in 2015 compared to $1.2 million in 2014 and reductions in the depreciation expenseprimarily due to the sale of the East Bend plant in December 2014Plant and the closureretirement of the Beckjord plant in 2014,Plant, partially offset by routineincreased depreciation associated with increased ARO assets and net plant additionsadditions.

For the nine months ended September 30, 2015, Depreciation and replacements. 

amortization expense decreased $4.7 million compared to the same period in the prior year primarily due to the sale of the East Bend Plant and the retirement of



82
Table of Contents

the Beckjord Plant, partially offset by increased depreciation associated with increased ARO assets and net plant additions.

DP&L – General Taxes

For the three months ended March 31,September 30, 2015, General taxes did not change significantly from the same period in the prior year.

For the nine months ended September 30, 2015, General taxes decreased $3.4$2.1 million compared to the same period in the prior year. The decrease was primarily due to a 2014 adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments made in 2014 partially offset by higher property tax accruals for 2015 compared to 2014. 

the prior year.


DP&L – Interest Expense

Interest expense recorded during the three months ended March 31,September 30, 2015 increased $0.9decreased $2.5 million compared to the same period in the prior year due toyear. This was primarily driven by debt prepayments and the refinancing of certain debt as well as the timing of accrualsdeferrals and recoveries of carrying charges on DP&L’s regulatory riders. AccrualsDeferrals of carrying charges are recorded as a creditdecrease to interest expense, while recoveries are recorded as an increase to interest expense.

DP&L – Income Tax Expense 

For


Interest expense during the threenine months ended March 31,September 30, 2015 Income tax expense increased $10.8decreased $0.9 million compared to the same period in 2014,the prior year. This was primarily driven by debt prepayments and the refinancing of certain debt as well as the timing of deferrals and recoveries of carrying charges on DP&L’s regulatory riders.

DP&L – Income Tax Expense
For the three months ended September 30, 2015, Income tax expense decreased $12.3 million compared to the same period in the prior year primarily due to higherlower pre-tax income in 2015 and an anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return to include the domestic manufacturing deduction. Partially offsetting the decrease is the 2014 adjustment to the tax reserves which did not occur in 2015.

For the nine months ended September 30, 2015, Income tax expense increased $1.9 million compared to the same period in the prior year primarily due to a 2014 adjustment to the tax reserves which did not occur in 2015.

Partially offsetting the 2014 adjustment is the anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return to include the domestic manufacturing deduction.




83

74

Table of Contents


FINANCIAL CONDITION, LLIQUIDITY AND CAPITAL REQUIREMENTS

DPL’siquidity AND Capital ReQUIREMENTS    

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


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


Net cashfromoperating activities

The revenue from our utility business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes. For the threenine months ended March 31,September 30, 2015, there was net cash from operating activities of $65.9 million.  This was a $53.0increased $86.0 million increase compared to the net cash from operating activities for the threenine months ended March 31,September 30, 2014 and was primarily driven by higher net income adjusted for depreciation and amortization, and the impact of deferred income taxtaxes, 2014 impairments, increased supplier security deposits related to the competitive bid process and the timing of collections year over year.


Net cash from investing activities

DuringCapital expenditures, primarily related to transmission and distribution continue to be our principal use of cash related to investing activities. For the threenine months ended March 31,September 30, 2015, and 2014,Netthere was a $3.9 million decrease in net cash used forby investing activities wascompared to the nine months ended September 30, 2014, primarily fordriven by the change in restricted cash year over year and less purchases of renewable energy credits in 2015, partially offset by increased capital expenditures at our generation plants.in 2015.


Net cash from financing activities

During the threenine months ended March 31,September 30, 2015,DPL issued $125.0 million of long-term debt and paid $160.0 million of long-term debt related to the refinancing of its term loan. DP&L issued $200.0 million of long-term debt and paid $314.5 million for the retirement of long-term debt. In addition, DP&L borrowed and repaid $15.0$50.0 million from its revolving credit facilities.  In addition, DP&Lfacilities and repaid $40.0 million, and paid dividends on its preferred stock and on its common stock to parent.its parent,

DPL.


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

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges and dividend payments. In 2015 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as 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 these periods.

In recent weeks both the PUCO and the OAQDA have approved plans for DP&L to refinance up to $210.0 million of tax-exempt debt, these transactions are expected to close late in the second quarter or early in the third quarter of 2015.


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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

Type

 

 

Maturity

 

 

Commitment

 

Amounts available as of March 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L

 

Revolving

 

 

May 2018

 

 

$

300.0 

 

$

298.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL

 

Revolving

 

 

May 2018

 

 

 

100.0 

 

 

97.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

400.0 

 

$

396.3 

$ in millions Type Maturity Commitment Amounts available as of filing date
DP&L Revolving July 2020 $175.0
 $163.6
DPL Revolving July 2020 205.0
 202.7
      $380.0
 $366.3

DP&L’s&L has an unsecured revolving credit agreement with a syndicated bank group. Prior to refinancing the facility established inon July 31, 2015, as discussed below, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 2013, expires in May10, 2018, and has nine participating banks, with no bank having more than 22.5% of the total commitment.  This revolving credit facility has a $100.0 million letter of credit sublimit and a feature that provided DP&L also has the optionability to increase the potential borrowing amountsize of the facility by an additional $100.0 million.



84
Table of Contents

On July 31, 2015, DP&L refinanced its revolving credit facility, reducing the total size from $300.0 million to $175.0 million, with a $50.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million, and extending the life of the facility from May 2018 to July 2020. At September 30, 2015, DP&L had drawn $10.0 million under this facility by $100.0 million.  At March 31, 2015, there wereand had two letters of credit in the amount of $1.4 million outstanding, with the remaining $298.6$163.6 million available to DP&L.

75

TableFees associated with this letter of Contents

credit facility were not material during the nine months ended September 30, 2015 or 2014.


DPL’sDPL has a revolving credit facility. This facility has a letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility. Prior to refinancing the facility on July 31, 2015, as discussed below, this facility was establishedunsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million and had a five year term expiring on May 2013.  This facility expires in May10, 2018; however,with a springing maturity, meaning that if DPL hashad not refinanced its $130.0 million of senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this credit facility will expire inwould have been July 15, 2016.  This facility has nine participating banks with no bank having more than 20% of the total commitment.

On July 31, 2015, DPL’sDPL refinanced its revolving credit facility, hasincreasing the total size from $100.0 million to $205.0 million, with a $100.0$200.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $50.0 million.  As$95.0 million This facility is secured by a pledge of March 31, 2015, there was one letter of credit issuedcommon stock that DPL owns inDP&L, limited to the amount of $2.3 million with the remaining $97.7 million availablepermitted 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 DPLE secured by assets of DPLE. On October 29, 2015,

DPL further secured the credit facility through a leasehold mortgage on additional assets of DPLE. The refinancing extended the life of the facility from May 2018 to July 2020. DPL's new 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 July 31, 2020, then the maturity of this facility shall be July 1, 2019.


Cash and cash equivalents for DPL and DP&L amounted to $48.5$43.0 million and $6.5$10.7 million, respectively, at March 31,September 30, 2015. At that date, neither DPLnor DP&L had any short-term investments that were not included in cash and cash equivalents.

Capital Requirements

Planned construction additions for 2015 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors.


DPL is projecting to spend an estimated $437.0$469.0 million in capital projects for the period 2015 through 2017, of which $378.0$383.0 million is projected to be spent by DP&L. DP&Lis subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions of which DP&L is a member. DP&L anticipates spending approximately $67.0$6.8 million within the next five years to reinforce its 138 kV system to comply with NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.


Debt Covenants

The DPL revolving credit facility and the DPL term loan agreement have a Total Debt to EBITDA ratio that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreements is not to exceed 8.507.25 to 1.00 for any fiscal quarter ending JuneSeptember 30, 20132015 through December 31, 2014;2018; it then steps down to not exceed 8.006.25 to 1.00 for any fiscal quarter ending March 31, 20152019 through December 31, 2016;2019; and it then steps down not to exceed 7.505.75 to 1.00 for any fiscal quarter ending March 31, 20172020 through MarchJuly 31, 2018.2020. As of March 31,September 30, 2015, the financial covenant was met with a ratio of 5.215.13 to 1.00.


The DPL revolving credit facility and the DPL term loan agreement also have an EBITDA to Interest Expense ratio that is calculated at the end of each fiscal quarter by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreements, is to be not less than 2.00 to 1.00 for any fiscal quarter ending June 30, 2013 through December 31, 2014; it then steps up to be not less than 2.10 to 1.00 for any fiscal quarter ending March 31,September 30, 2015 through December 31, 2016; and2018; it then steps up to be not less than 2.25 to 1.00 for any fiscal quarter ending March 31, 20172019 through MarchJuly 31, 2018.2020. As of March 31,September 30, 2015, this financial covenant was met with a ratio of 3.453.31 to 1.00.



85
Table of Contents


DP&L’s revolving credit facility has atwo financial covenant that requirescovenants. 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 tomay not exceedbe greater than 0.65 to 1.00.1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that required compliance with this financial covenant shall be suspended if 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. As of March 31,September 30, 2015, DP&L met this financial covenant was met with a ratio of 0.440.39 to 1.00. The above ratioThis covenant is calculated as the sum of DP&L’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DP&L’s shareholder’s equity and total debt including guarantee obligations.  In addition,debt. The above covenant was retained in DP&L’s revolving credit facility refinanced on July 31, 2015, and was modified only such that this covenant shall also be 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.

The DP&L revolving credit facility also has an EBITDA to Interest Expense ratiofinancial covenant that will be calculated at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. Both prior to and after completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. As of March 31,September 30, 2015, this covenant was met with a ratio of 11.3010.83 to 1.00.

76


Table of Contents

Debt and Credit Ratings

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

DPL

DPL (a)

DP&L

DP&L (b)

Outlook

Outlook

Effective

Fitch Ratings

BB(a) / BB-(b)

BB

BBB (c)

BBB

Stable

Stable

August 2015 / September 2014

(d)

Moody's Investors Service, Inc.

Ba3 (b)

Ba3

Baa2 (c)

Baa2

Stable

Stable

September 2014

October 2015

Standard & Poor's Financial Services LLC

BB (b)

BB

BBB- (c)

BBB-

Stable

Stable

May 2014

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

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

Credit Ratings 


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

DPL

DPL

DP&L

DP&L

Outlook

Outlook

Effective

Fitch Ratings

B+

B+

BB+

BB+

Stable

Stable

August 2015 / September 2014

(d)

Moody's Investors Service, Inc.

Ba3

Ba3

Baa3

Baa3

Stable

Stable

September 2014

October 2015

Standard & Poor's Financial Services LLC

BB

BB

BB

BB

Stable

Stable

May 2014


(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.
(d)
DPL ratings were updated in August 2015; DP&L ratings have not been updated since September 2014.

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


Off-Balance Sheet Arrangements

For information on guarantees, commercial commitments, and contractual obligations, see Note 910 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 1011 of Notes to DP&L’s Condensed Financial Statements.




86
Table of Contents

Market Risk


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

77


Table of Contents

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.  contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market unless they qualify for cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis through the Statement of Operations or, where applicable, we recognize a corresponding Regulatory asset for above-market costs or a Regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.


The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2015 under contract,contract; sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January 2010, our results of operations, financial condition or cash flows could be materially affected.


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


Commodity Derivatives

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


A 10% increase or decrease in the market price of our heating oil forwards and FTRs at March 31,September 30, 2015 would not have a significant effect on Net income.


At March 31,September 30, 2015, a 10% increase or decrease in the market price of our forward power purchase contracts would result in an impact on unrealized gains/losses of $2.8$12.3 million, while a 10% increase or decrease in the market price of our forward power sale contracts would result in an impact on unrealized gains/losses of $12.6$4.0 million.

78




87

Table of Contents


Wholesale Revenues

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL

 

Three months ended

 

 

March 31,

 

 

2015

 

2014

Percent of electric revenues from wholesale market

 

 

27% 

 

 

13% 

 

 

 

 

 

 

 

DP&L

 

Three months ended

 

 

March 31,

 

 

2015

 

2014

Percent of electric revenues from wholesale market

 

 

49% 

 

 

42% 

DPL Three months ended Nine months ended
  September 30, September 30,
  2015 2014 2015 2014
Percent of electric revenues from wholesale market 27% 22% 27% 16%
         
DP&L Three months ended Nine months ended
  September 30, September 30,
  2015 2014 2015 2014
Percent of electric revenues from wholesale market 43% 49% 45% 45%

The following table presents the effect on annual Net income (net of estimated income taxes at 35%) as of March 31,September 30, 2015, of a hypothetical increase or decrease of 10% in the price per MWh of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note that the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

DPL

 

DP&L

Effect of 10% change in price per MWh

 

$

12.3 

 

$

35.9 

RPM

$ in millions DPL DP&L
Effect of 10% change in price per MWh $14.0
 $12.8

Capacity Revenues and Costs

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year that runs from June 1 to May 31, has conducted auctions for capacity through the delivery year. The clearing prices for capacity during the PJM delivery periods from 2013/142014/15 through 2017/182018/19 are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PJM Delivery Year

($/MW-day)

2013/14

 

2014/15

 

2015/16

 

2016/17

 

2017/18

Capacity clearing price

$

28 

 

$

126 

 

$

136 

 

$

59 

 

$

120 

  PJM Delivery Year
($/MW-day) 2014/15 2015/16 2016/17 2017/18 2018/19
Capacity clearing price $126
 $136
 $134
 $152
 $165

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Calendar Year

($/MW-day)

2013

 

2014

 

2015

 

2016

 

2017

Computed average capacity price

$

23 

 

$

85 

 

$

132 

 

$

91 

 

$

95 

  Calendar Year
($/MW-day) 2014 2015 2016 2017 2018
Computed average capacity price $85
 $132
 $135
 $145
 $159

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. 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. AlthoughRPM costs and revenues associated with the DP&L currently has an approved RPM riderportion of the SSO supply are included in place to recover or repay any excess capacity costs or revenues, the RPM rider only applieswhich will be phased out as a result of SSO load being served via 100% competitive bid beginning January 2016. As discussed above, the FERC approved a proposal made by PJM to customers supplied under our SSO.  Customer switching reducesimplement a new CP program. The FERC’s conditions on approval include requiring PJM to make additional filings to change certain energy market rules to coordinate better with the numbernew CP program and to make annual filings on the CP performance hours used in its calculations.



88
Table of customers supplied under our SSO, causing more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.    

Contents


The following table provides estimates of the effect on annual Net income (net of estimated income taxes at 35%) as of March 31,September 30, 2015 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.changes, using the percent of SSO customers as of the balance sheet date and the percentage of our supply we are required to source through auction. We did not include the impact of a

79

Table of Contents

change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$ in millions

 

DPL

 

DP&L

Effect of $10/MW-day change in capacity auction pricing

 

$

6.4 

 

$

5.1 

$ in millions DPL DP&L
Effect of $10/MW-day change in capacity auction pricing $7.0
 $5.7

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


Fuel and Purchased Power Costs

DPL’s and DP&L’sfuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the threenine months ended March 31,September 30, 2015 were 43% and 41%44%, respectively. We have a significant portion of projected 2015 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2allowances for 2015, however, the exact consumption of SO2allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOxNOx allowances for 2015 depending on NOxNOx emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.


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


Effective January 1, 2010, DP&L was allowed to recover its SSO retail customers’ share of fuel and purchased power costs as part of the fuel rider approved by the PUCO. As a result of customer switching and 60% of our SSO load being sourced through a competitive bid auction, less of DP&L’sfuel costs are recoverable from retail customers. Beginning January 1, 2016, 100% of the SSO will be sourced through a competitive bid, therefore at that time the fuel rider will be phased out.


The following table provides the effect on annual Net income (net of estimated income taxes at 35%) using the estimated SSO share of costs as of March 31,September 30, 2015 and the current 60% of SSO load sourced through the competitive bid auction, 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

 

$

36.6 

 

$

36.9 

$ in millions DPL DP&L
Effect of 10% change in fuel and purchased power $35.3
 $35.6

Interest Rate Risk

As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL and DP&Lhave both fixed-rate and variable-rate long-term debt. DPL’s variable-rate debt consists of a $160.0$125.0 million unsecured term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s variable-rate debt is comprised of publiclybank held pollution control bonds. The variable-rate bonds bear interest based on a prevailingan underlying interest rate that is reset weekly based on a comparable market index.index, typically LIBOR. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 45 of Notes to DPL’sCondensed Consolidated Financial Statements and Note 45 of Notes to DP&L’s Condensed Financial Statements.


In the past, DPL partially hedged against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing activities. As of March 31,September 30, 2015, DPL has settled all outstanding interest rate swaps and has no interest rate swaps outstanding.swaps. Any additional credit rating downgrades could affect our liquidity and further increase our cost of capital.


80


89

Table of Contents



Principal Payments and Interest Rate Detail by Contractual Maturity Date

The carrying value of DPL’s debt was $2,159.7$2,009.4 million at March 31,September 30, 2015, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’sfirst mortgage bonds, tax-exempt pollution control bonds and the Wright-Patterson Air Force Base note. All of DPL’s debt was adjusted to fair value at the date of the Merger according to FASC 805.Merger. The fair value of this debt at March 31,September 30, 2015 was $2,238.5$2,033.7 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations, subsequent to the refinancing discussed above, that are sensitive to interest rate changes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Principal payments due

 

 

 

 

 

 

 

during the twelve months ending

 

 

 

 

At March 31, 2015

 

March 31,

 

 

 

 

Principal

 

Fair

$ in millions

2016

 

2017

 

2018

 

2019

 

2020

 

Thereafter

 

Amount

 

Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable-rate debt

$

30.0 

 

$

40.0 

 

$

40.0 

 

$

50.0 

 

$

 -

 

$

100.0 

 

$

260.0 

 

$

260.0 

Average interest rate (a)

 

2.4%

 

 

2.4%

 

 

2.4%

 

 

2.4%

 

 

      -

 

 

0.1%

 

 

 

 

 

 

Fixed-rate debt

$

0.1 

 

$

575.1 

 

$

0.1 

 

$

0.2 

 

$

200.2 

 

$

1,127.5 

 

 

1,903.2 

 

 

1,978.5 

Average interest rate

 

4.2%

 

 

2.9%

 

 

4.2%

 

 

4.2%

 

 

6.7%

 

 

6.5%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

2,163.2 

 

$

2,238.5 

(a)Based on rates in effect at March 31, 2015

DPL                
  Principal payments due At September 30, 2015
  during the twelve months ending   
  September 30,   Principal Fair
$ in millions 2016 2017 2018 2019 2020 Thereafter Amount Value
Variable-rate debt $—
 $18.8
 $25.0
 $25.0
 $256.2
 $—
 $325.0
 $325.0
Average interest rate (a)
 —% 2.4% 2.4% 2.4% 1.4% —%    
Fixed-rate debt $445.1
 $130.1
 $0.1
 $0.2
 $200.2
 $913.0
 1,688.7
 1,708.7
Average interest rate 1.9% 6.5% 4.2% 4.2% 6.7% 6.9%    
Total             $2,013.7
 $2,033.7

(a)
Based on rates in effect at September 30, 2015

The carrying value of DP&L’s debt was $877.2$762.9 million at March 31,September 30, 2015, consisting of its first mortgage bonds, tax-exempt pollution control bonds and the Wright-Patterson Air Force Base note. The fair value of this debt was $885.2$764.3 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DP&L’s debt obligations, subsequent to the refinancing discussed in the "Financial Condition, Liquidity and Capital Requirements" section above, that are sensitive to interest rate changes. DP&L’s debt was not revalued as a result of the Merger.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Principal payments due

 

 

 

 

 

 

 

during the twelve months ending

 

 

 

 

At March 31, 2015

 

March 31,

 

 

 

 

Principal

 

Fair

$ in millions

2016

 

2017

 

2018

 

2019

 

2020

 

Thereafter

 

Amount

 

Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable-rate debt

$

 -

 

$

 -

 

$

 -

 

$

 -

 

$

 -

 

$

100.0 

 

$

100.0 

 

$

100.0 

Average interest rate (a)

 

      -

 

 

      -

 

 

      -

 

 

      -

 

 

      -

 

 

0.1%

 

 

 

 

 

 

Fixed-rate debt

$

0.1 

 

$

445.1 

 

$

0.1 

 

$

0.2 

 

$

0.2 

 

$

331.9 

 

 

777.6 

 

 

785.2 

Average interest rate

 

4.2%

 

 

1.9%

 

 

4.2%

 

 

4.2%

 

 

4.2%

 

 

4.8%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

877.6 

 

$

885.2 

(a)Based on rates in effect at March 31, 2015

81

DP&L                
  Principal payments due At September 30, 2015
  during the twelve months ending   
  September 30,   Principal Fair
$ in millions 2016 2017 2018 2019 2020 Thereafter Amount Value
Variable-rate debt $—
 $—
 $—
 $—
 $200.0
 $—
 $200.0
 $200.0
Average interest rate (a)
 —% —% —% —% 1.1% —%    
Fixed-rate debt $445.1
 $0.1
 $0.1
 $0.2
 $0.2
 $117.4
 563.1
 564.3
Average interest rate 1.9% 4.2% 4.2% 4.2% 4.2% 4.7%    
Total             $763.1
 $764.3

Table of Contents


(a)Based on rates in effect at September 30, 2015


Debt maturities and repayments occurring in 2015 are discussed under FINANCIAL"FINANCIAL CONDITION, LiquidityLIQUIDITY AND Capital ReQUIREMENTS.

CAPITAL REQUIREMENTS".


Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at March 31,September 30, 2015 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of March 31,September 30, 2015, we did not hold any market risk sensitive instruments that were entered into for trading purposes.




90
Table of Contents

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DPL

 

 

 

At March 31, 2015

 

One percent

 

 

 

 

Carrying

 

Fair

 

interest rate

$ in millions

 

Value

 

Value

 

risk

Long-term debt

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable-rate debt

 

$

260.0 

 

$

260.0 

 

$

2.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed-rate debt

 

 

1,899.7 

 

 

1,978.5 

 

 

19.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

2,159.7 

 

$

2,238.5 

 

$

22.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DP&L

 

 

 

At March 31, 2015

 

One percent

DPL At September 30, 2015 One percent

 

 

 

Carrying

 

Fair

 

interest rate

 Carrying Fair interest rate

$ in millions

$ in millions

 

Value

 

Value

 

risk

 Value Value risk

Long-term debt

Long-term debt

 

 

 

 

 

 

 

 

 

 

      

 

 

 

 

 

 

 

 

 

 

 

 

Variable-rate debt

Variable-rate debt

 

$

100.0 

 

$

100.0 

 

$

1.0 

 

 $325.0
 $325.0
 $3.3

 

 

 

 

 

 

 

 

 

 

 

 

      

Fixed-rate debt

Fixed-rate debt

 

 

777.2 

 

 

785.2 

 

 

7.9 

 

 1,684.4
 1,708.7
 17.1

 

 

 

 

 

 

 

 

 

 

 

 

      

Total

Total

 

$

877.2 

 

$

885.2 

 

$

8.9 

 

 $2,009.4
 $2,033.7
 $20.4


DP&L At September 30, 2015 One percent
  Carrying Fair interest rate
$ in millions Value Value risk
Long-term debt      
Variable-rate debt $200.0
 $200.0
 $2.0
       
Fixed-rate debt 562.9
 564.3
 5.6
       
Total $762.9
 $764.3
 $7.6

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s$1,978.5 $1,708.7 million of fixed-rate debt and not on DPL’s financial condition or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DPL’s$260.0 $325.0 million variable-rate long-term debt outstanding as of March 31,September 30, 2015.


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 $785.2564.3 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $100.0$200.0 million variable-rate long-term debt outstanding as of March 31,September 30, 2015.


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

82

Table of Contents

or counterparty performance, whether reflected on or off the balance sheet. We limit our credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been originated. We use the three leading corporate credit rating agencies and other current market-based qualitative and quantitative data to assess the financial strength of our counterparties on an ongoing basis. We may require various forms of credit assurance from our counterparties in order to mitigate credit risk.




91
Table of Contents

Critical Accounting Estimates


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


Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; the valuation of AROs; assets and liabilities related to employee benefits and goodwill and intangible assets.assets. Refer to our Form 10-K for the fiscal year ended December 31, 2014 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ELECTRIC SALES AND CUSTOMERS

 

 

DPL

 

DP&L (a)

 

DPLER (b)

 

 

Three months ended

 

Three months ended

 

Three months ended

 

 

March 31,

 

March 31,

 

March 31,

 

 

2015

 

 

2014

 

2015

 

 

2014

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric Sales (millions of kWh)

 

 

5,082 

 

 

 

5,375 

 

 

4,971 

 

 

 

5,314 

 

 

2,048 

 

 

 

2,782 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Billed electric customers (end of period)

 

 

650,712 

 

 

 

699,619 

 

 

516,324 

 

 

 

515,748 

 

 

258,755 

 

 

 

322,291 

(a)This table contains electric sales from DP&L’s generation and purchased power.  DP&L sold 1,149 million kWh and 1,604 million kWh of power to DPLER during the three months ended March 31, 2015 and 2014, respectively, not included above to avoid duplication.    

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

  ELECTRIC SALES AND CUSTOMERS
  DPLDP&L (a)DPLER (b)
  Three months endedThree months endedThree months ended
  September 30,September 30,September 30,
  201520142015201420152014
Electric Sales (millions of kWh) 4,349
5,134
4,297
5,112
1,391
2,498
        
Billed electric customers (end of period) 531,051
653,801
515,372
514,371
128,405
274,133

(a)
This table contains electric sales from DP&L’s generation and purchased power. DP&L sold 991 million kWh and 1,367 million kWh of power to DPLER during the three months ended September 30, 2015 and 2014, respectively, not included above to avoid duplication.
(b)
This chart includes all sales of DPLER, both within and outside of the DP&L service territory.

  ELECTRIC SALES AND CUSTOMERS
  DPLDP&L (a)DPLER (b)
  Nine months endedNine months endedNine months ended
  September 30,September 30,September 30,
  201520142015201420152014
Electric Sales (millions of kWh) 12,980
14,352
12,735
14,220
4,762
7,614
        
Billed electric customers (end of period) 531,051
653,801
515,372
514,371
128,405
274,133

(a)
This table contains electric sales from DP&L’s generation and purchased power. DP&L sold 3,094 million kWh and 4,366 million kWh of power to DPLER during the nine months ended September 30, 2015 and 2014, respectively, not included above to avoid duplication.
(b)
This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory.

Item 3.  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.




92
Table of Contents

Item 4.  4 – Controls and Procedures


Disclosure Controls and Procedures

83

Table of Contents

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries areis communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that, as of March 31,September 30, 2015, our disclosure controls and procedures were not effective 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, as evidenced by the previously reported material weakness described below.

As a result of the material weakness described below, the Company performed additional analysis and other procedures in order to ensure the proper preparation of the financial statements in accordance with generally accepted accounting principles in the United States of America. This material weakness did not result in any misstatements in the Company’s audited financial statements.  Accordingly, management believes that the financial statements included in this Form 10-Q fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.

forms.



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 March 31,September 30, 2015. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”) in 2013. As disclosed in our Form 10-K for the fiscal year ended December 31, 2014, management determined that a material weakness in internal control over financial reporting existed as of December 31, 2014 as a result of an incorrect formula within the spreadsheet used to support an account balance, creating an understatement of earnings. The CompanyDPL determined that sufficient controls did not exist to identify this error in a timely manner; therefore this deficiency could have led to a material error in the financial statements. As evidenced by this material weakness, management concluded that, as of December 31, 2014, the CompanyDPL did not maintain effective internal control over financial reporting. ManagementThis material weakness did not result in any misstatements in our audited financial statements. In response to this material weakness, changes were made to our internal control over financial reporting, including enhancements to our journal entry and spreadsheet reviews. We has developedcompleted the documentation and is in the processtesting of implementing athese corrective action plan related to the operating effectivenessactions and as of the control described above. September 30, 2015, has concluded that this material weakness has been remediated. There were no other 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 Board of Directors are committed to the remediation of this material weakness as well as the continued improvement of the Company’sDPL's overall system of internal control over financial reporting.


Part II – Other information

Information


Item 1.1 – Legal Proceedings


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


Our Form 10-K for the fiscal year ended December 31, 2014, and Form 10-Q for the three months ended March 31, 2015, six months ended June 30, 2015 and the Notes to DPL’s Consolidated Financial Statements and DP&L’s Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II of our Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Form 10-K and Form 10-Qs, and should be read in conjunction with thesuch Form 10-K.    10-K and Form 10-Q.

84


Table of Contents

The following information is incorporated by reference into this Item:  (i) information about the legal proceedings contained in Part I, Item 1 — Note 910 of Notes to DPL’sCondensed Consolidated Financial Statements and Note 1011 of Notes to DP&L’s Condensed Financial Statements of this Quarterly Report on Form 10-Q.



93
Table of Contents


Item 1A.    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, 2014. ThereAs of September 30, 2015, there have been no material changes with respect to the risk factors disclosed in our Form 10-K. If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.


The risks and uncertainties described in our risk factors are not the only ones we face. In addition, new risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. Our risk factors should be read in conjunction with the other detailed information concerning DPLand 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.    2 – Unregistered Sale of Equity Securities and Use of Proceeds


None


Item 3.3 – Defaults Upon Senior Securities


None


Item 4.4 – Mine Safety Disclosures


Not applicable.


Item 5.5 – Other Information


None

85




94

Table of Contents


Item 6.    6 – Exhibits

DPL Inc.

DP&L

Exhibit Number

Exhibit

Location

DPL Inc.

DP&L

Exhibit Number

Exhibit

Location

X

31(a)

X10(a)Open-End Leasehold Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing from DPL Energy, LLC to U.S. Bank National Association, dated as of October 29, 2015Filed herewith as Exhibit 10 (a)
X31(a)Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002    

Filed herewith as Exhibit 31(a)

X

31(b)

Certification of Chief Financial Officer 

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Filed herewith as Exhibit 31(b)

X

31(c)

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002    

Filed herewith as Exhibit 31(c)

X

31(d)

Certification of Chief Financial Officer 

pursuant to Section 302 of the Sarbanes-Oxley Act of 2002    

Filed herewith as Exhibit 31(d)

X

32(a)

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002    

Filed herewith as Exhibit 32(a)

X

32(b)

Certification of Chief Financial Officer 

pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith as Exhibit 32(b)

X

32(c)

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002    

Filed herewith as Exhibit 32(c)

X

32(d)

Certification of Chief Financial Officer 

pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith as Exhibit 32(d)

86

Table of Contents

DPL Inc.

X

DP&L

X

Exhibit Number

101.INS

Exhibit

Location

X

X

101.INS

XBRL Instance

Filed herewith as Exhibit 101.INS    

X

X

101.SCH

XBRL Taxonomy Extension Schema

Filed herewith as Exhibit 101.SCH    

X

X

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

Filed herewith as Exhibit 101.CAL

X

X

101.DEF

XBRL Taxonomy Extension Definition Linkbase

Filed herewith as Exhibit 101.DEF    

X

X

101.LAB

XBRL Taxonomy Extension Label Linkbase

Filed herewith as Exhibit 101.LAB    

X

X

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

Filed 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.

87




95

Table of Contents


SIGNATURES

SIGNATURES    


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


DPL Inc.

(Registrant)

Date:

November 4, 2015

Date:

May 8, 2015

/s/ Kenneth J. Zagzebski

(Kenneth J. Zagzebski)

Zagzebski

President and Chief Executive Officer

(principal executive officer)

November 4, 2015

May 8, 2015

/s/ Craig L. Jackson

(Craig L. Jackson)

Jackson

Chief Financial Officer

(principal financial officer)

November 4, 2015

May 8, 2015

/s/ Kurt A. Tornquist

(Kurt A. Tornquist)

Tornquist

Controller

(principal accounting officer)


88


96

Table of Contents


SIGNATURES


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


The Dayton Power and Light Company

(Registrant)

Date:

November 4, 2015

Date:

May 8, 2015

/s/ Thomas A. Raga

(Thomas A. Raga)

Raga

President and Chief Executive Officer

(principal executive officer)

November 4, 2015

May 8, 2015

/s/ Craig L. Jackson

(Craig L. Jackson)

Jackson

Chief Financial Officer

(principal financial officer)

November 4, 2015

May 8, 2015

/s/ Kurt A. Tornquist

(Kurt A. Tornquist)

Tornquist

Controller

(principal accounting officer)


89


97