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Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
DPL
Inc.
Yes o
No x
The Dayton Power and Light Company
Yes o
No x
Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
DPL
Inc.
Yes x
No o
The Dayton Power and Light Company
Yes x
No o
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
1
DPL Inc. and The Dayton Power and Light Company are voluntary filers that have filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.
Indicate
by check mark whether each registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).
DPL Inc.
Yes x
No o
The Dayton Power and Light Company
Yes x
No
o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
DPL Inc.
x
The Dayton Power and Light Company
x
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large
accelerated
filer
Accelerated
filer
Non-
accelerated
filer
(Do
not check if a smaller reporting company)
Smaller
reporting
company
Emerging growth company
DPL Inc.
o
o
x
o
o
The Dayton Power and Light Company
o
o
x
o
o
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
DPL Inc.
o
The Dayton Power and Light Company
o
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
DPL
Inc.
Yes o
No x
The Dayton Power and Light Company
Yes o
No x
All of the outstanding common stock of DPL Inc. is indirectly owned by The AES Corporation. All of the common stock of The Dayton Power and Light Company is owned by DPL Inc.
2
At December
31, 2018, each registrant had the following shares of common stock outstanding:
This combined Form 10-K is separately filed by DPL Inc. and The Dayton Power and Light Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.
THE REGISTRANTS MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.
3
DPL Inc. and The Dayton Power
and Light Company - Annual Report on Form 10-K
AEP Generation Resources Inc., a subsidiary of American Electric Power Company, Inc. (“AEP”). Columbus Southern Power Company merged
into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011. The Ohio Power generating assets (including jointly-owned units) were transferred into AEP Generation.
AES
The AES Corporation, a global power company, the ultimate parent company of DPL
AES Ohio Generation
AES Ohio Generation, LLC, a wholly-owned subsidiary of DPL that owns and operates a generation facility from which it makes wholesale sales
AFUDC
Allowance for Funds Used During Construction
AMI
Advanced
Metering Infrastructure
AOCI
Accumulated Other Comprehensive Income
ARO
Asset Retirement Obligation
ASU
Accounting Standards Update
CAA
U.S. Clean Air Act
Capacity Market
The purpose of the capacity market is to enable PJM to obtain sufficient resources to reliably meet the needs of electric
customers within the PJM footprint. PJM procures capacity, through a multi-auction structure, on behalf of the load serving entities to satisfy the load obligations. There are four auctions held for each Delivery Year (running from June 1 through May 31). The Base Residual Auction is held three years in advance of the Delivery Year and there is one Incremental Auction held in each of the subsequent three years. AES Ohio Generation's capacity is in the “rest of” RTO area of PJM.
CCR
Coal Combustion Residuals, which consists of bottom ash, fly ash, and air pollution
Conesville
AES Ohio Generation's interest in Unit 4 at the Conesville EGU which is operated by AEP
CPP
The
Clean Power Plan, the USEPA's final carbon dioxide emission rules for existing power plants under Clean Air Act Section 111(d)
CRES
Competitive Retail Electric Service
CSAPR
Cross-State Air Pollution Rule
CWA
U.S. Clean Water Act
Dark spread
A common metric used to estimate returns over fuel costs of coal-fired EGUs
DOE
U.S.
Department of Energy
DMR
Distribution modernization rider - designed to allow DP&L to modernize and/or maintain its transmission and distribution infrastructure.
DPL
DPL Inc.
DPLER
DPL Energy Resources, Inc., formerly a wholly-owned subsidiary of DPL which sold competitive electric energy and other energy services. DPLER was sold on January 1, 2016 pursuant to an agreement dated December 28, 2015.
DP&L
The
Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells, transmits and distributes electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. DP&L is wholly-owned by DPL
DRO
Distribution Rate Order, the order issued by the PUCO on September 26, 2018 establishing new base distribution rates for DP&L, which became effective October 1, 2018
Dths
Decatherms, unit of heat energy equal to 10 therms. One therm is equal to 100,000 British Thermal Units
Duke
Energy
Affiliates of Duke Energy with which DP&L co-owns transmission lines in Ohio (Duke Energy Ohio, Inc.)
Dynegy
Dynegy, Inc., the parent of various subsidiaries that, along with AEP Generation and AES Ohio Generation, co-owns coal-fired EGUs in Ohio
EBIT
Earnings before interest and taxes
EBITDA
Earnings before interest, taxes, depreciation and amortization
EGU
Electric
Generating Unit
ELG
Steam Electric Power Effluent Limitations Guidelines
ERISA
The Employee Retirement Income Security Act of 1974
ESP
The Electric Security Plan is a cost-based plan that a utility may file with the PUCO to establish SSO rates pursuant to Ohio law
FASB
Financial Accounting Standards Board
FASC
FASB
Accounting Standards Codification
FERC
Federal Energy Regulatory Commission
First and Refunding Mortgage
DP&L’s First and Refunding Mortgage, dated October 1, 1935, as amended, with the Bank of New York Mellon as Trustee
FTR
Financial Transmission Rights
GAAP
Generally Accepted Accounting Principles in the United States of America
5
GLOSSARY
OF TERMS (cont.)
Term
Definition
Generation Separation
The transfer on October 1, 2017, to AES Ohio Generation of the DP&L-owned generating facilities and related liabilities, excluding those of the Beckjord Facility and Hutchings EGU, pursuant to an asset contribution agreement with a subsidiary that was then merged into AES Ohio Generation
GHG
Greenhouse gas
kV
Kilovolts,
1,000 volts
kWh
Kilowatt hour
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 Standards
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.
Miami Valley Lighting
Miami Valley Lighting, LLC is a wholly-owned subsidiary of DPL established in 1985 to provide street and outdoor lighting services to customers in the Dayton region. Miami Valley Lighting serves businesses, communities and neighborhoods in West Central Ohio with over 70,000 lighting solutions for more than 190 businesses and 180 local governments.
MRO
Market Rate Option, a market-based plan that a utility may file with PUCO to establish SSO rates 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
MW
Megawatt
MWh
Megawatt hour
NAAQS
National Ambient Air Quality Standards
NAV
Net asset value
NERC
North
American Electric Reliability Corporation
Non-bypassable
Charges that are assessed to all customers regardless of whom the customer selects as their retail electric generation supplier
NOV
Notice of Violation
NOX
Nitrogen Oxide
NPDES
National Pollutant Discharge Elimination System
NSR
New
Source Review: a preconstruction permitting program regulating new or significantly modified sources of air pollution
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 has a 4.9% interest
Peaker assets
The
generation and related assets for the 586.0 MW Tait combustion turbine and diesel generation facility, the 236.0 MW Montpelier combustion turbine generation facility, the 101.5 MW Yankee combustion turbine generation and solar facility, the 25.0 MW Hutchings combustion turbine generation facility, the 12.0 MW Monument diesel generation facility, and the 12.0 MW Sidney diesel generation facility
PJM
PJM Interconnection, LLC, an RTO
PRP
Potentially Responsible Party
PUCO
Public Utilities Commission of Ohio
RTO
Regional
Transmission Organization
SB 221
Ohio Senate Bill 221 is an Ohio electric energy bill that requires all Ohio distribution utilities to file either an ESP or MRO. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.
SEC
Securities and Exchange Commission
SEET
Significantly Excessive Earnings Test
Service Company
AES
US Services, LLC, the shared services affiliate providing accounting, finance, and other support services to AES’ U.S. SBU businesses
SIP
A State Implementation Plan is a plan for complying with the federal CAA, administered by the USEPA. The SIP consists of narrative, rules, technical documentation and agreements that an individual state will use to clean up polluted areas.
SO2
Sulfur Dioxide
SSO
Standard Service Offer represents the retail transmission, distribution and generation services offered by a utility through
regulated rates, authorized by the PUCO
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
This report includes the combined filing of DPL
and DP&L. DPL is a wholly-owned subsidiary of AES, a global power company. Throughout this report, the terms “we”, “us”, “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.
FORWARD–LOOKING STATEMENTS
Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act
of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of future economic performance, considering 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:
•
growth in our service territory and changes in demand and demographic patterns;
•
weather-related damage to our electrical system;
•
performance
of our suppliers;
•
transmission and distribution system reliability and capacity;
•
regulatory actions and outcomes, including, but not limited to, the review and approval of our rates and charges by the PUCO;
•
federal and state legislation and regulations;
•
changes
in our credit ratings or the credit ratings of AES;
•
fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and our ability to fund defined benefit pension plans;
▪
changes in financial or regulatory accounting policies;
▪
environmental matters, including
costs of compliance with, and liabilities related to, current and future environmental laws and requirements;
▪
interest rates and the use of interest rate hedges, inflation rates and other costs of capital;
▪
the availability of capital;
▪
the ability of subsidiaries to pay dividends
or distributions to DPL;
▪
level of creditworthiness of counterparties to contracts and transactions;
▪
labor strikes or other workforce factors, including the ability to attract and retain key personnel;
▪
facility or equipment maintenance,
repairs and capital expenditures;
▪
significant delays or unanticipated cost increases associated with construction projects;
▪
the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material;
▪
local
economic conditions;
▪
costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation;
▪
industry restructuring, deregulation and competition;
▪
issues related to our participation in PJM, including
the cost associated with membership, allocation of costs, costs associated with transmission expansion, the recovery of costs incurred, and the risk of default of other PJM participants;
▪
changes in tax laws and the effects of our strategies to reduce tax payments;
▪
product development, technology changes, and changes in prices of products and technologies;
▪
cyberattacks
and information security breaches;
▪
the use of derivative contracts;
▪
catastrophic events such as fires, explosions, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences; 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.
Item 1 – Business
OVERVIEW
DPL is a regional energy company incorporated in 1985 under the laws of Ohio. All of DPL’s stock is owned by an AES subsidiary.
DPL has three primary subsidiaries, DP&L,
MVIC and AES Ohio Generation. DP&L is a public utility providing electric transmission and distribution services in West Central Ohio. AES Ohio Generation owns an undivided interest in a coal-fired generating facility and sells all of its energy and capacity into the wholesale market. MVIC is our captive insurance company that provides insurance services to DPL and our other subsidiaries. For additional information, see Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DPL's Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L's
Financial Statements. All of DPL's subsidiaries are wholly-owned.
As an electric public utility in Ohio, DP&L provides regulated transmission and distribution services to its customers as well as retail SSO electric service. DP&L's sales reflect the general economic conditions, seasonal weather patterns and the growth of energy efficiency initiatives; however, our distribution revenues have been decoupled from weather and energy efficiency variations beginning January 1, 2019 as a result of the decoupling rider approved in the DRO. See Note 3 – Regulatory Matters of Notes to DPL's
Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements for further information.
DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&L does not have any subsidiaries.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. 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 or overcollections of riders.
GENERATING CAPACITY
DPL, through AES Ohio Generation, owns an undivided interest in Conesville. AES Ohio Generation's share of this EGU's capacity is 129 MW. AES Ohio Generation sells all of its energy and capacity into the wholesale market.
DP&L also has a 4.9%
interest in OVEC, an electric generating company. OVEC has two electric generating stations located in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of 2,109 MW. DP&L’s share of this generation capacity is 103 MW.
SEGMENTS
DPL manages its business through one reportable operating segment, the Utility segment. See Note 13 – Business Segments of the Notes to DPL's Consolidated Financial Statements for additional information regarding DPL’s
reportable segment.
DPL and its subsidiaries employed 659 people at January 31, 2019, of which 647 were employed by DP&L. Approximately 57% of all DPL employees are
under a collective bargaining agreement.
SERVICE COMPANY
The Service Company provides services including accounting, legal, human resources, information technology and other services of a similar nature on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated businesses served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses. See Note 12 – Related Party Transactions
of Notes to DPL's Consolidated Financial Statements and Note 12 – Related Party Transactions of Notes to DP&L's Financial Statements.
SEASONALITY
The power delivery business is seasonal, and weather patterns have a material effect on energy demand. In the region we serve, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating compared to other times of the year. DP&L's sales typically reflect the seasonal weather patterns and the
growth of energy efficiency initiatives, however, after the approval of the distribution rate order in 2018, our distribution revenues have been decoupled from weather and energy efficiency variations. Because of the impact of the new decoupling rider (effective January 1, 2019) and because DPL's generation has greatly decreased in recent years due to plant sales and closures, we expect that weather and other factors influencing demand will have minimal impact on our net operating results going forward.
Storm activity can also have an adverse effect on our operating performance. Severe storms often damage transmission and distribution equipment, thereby causing power outages, which increase repair costs. Partially mitigating this impact is DP&L’s
ability to recover certain repair costs related to severe storms.
MARKET STRUCTURE
Retail rate regulation
DP&L's delivery service to all retail customers as well as the provisions of its SSO service are regulated by the PUCO. In addition, certain costs are considered to be non-bypassable and are therefore assessed to all DP&L retail customers, under the regulatory authority of the PUCO, regardless of the customer’s retail electric supplier. DP&L's transmission rates are subject to regulation by the FERC under the Federal Power Act.
Ohio
law establishes the process for determining SSO and non-bypassable rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate changes, the cost basis upon which the rates are set and other service-related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.
Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCO's supervisory powers to a holding company system's general condition and capitalization, among other matters, to the extent that such matters relate to the costs associated with the provision of public utility
service. Based on existing PUCO and FERC authorization, regulatory assets and liabilities are recorded on the balance sheets of both DPL and DP&L. See Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements.
COMPETITION AND REGULATION
Ohio Retail Rates
DP&L
filed an amended stipulation to its 2017 ESP case on March 13, 2017. The PUCO issued a final decision on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The six-year 2017 ESP establishes DP&L's framework for providing retail service on a going-forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up rider mechanisms.
On September 26,
2018 the PUCO issued the DRO establishing new base distribution rates for DP&L, which became effective October 1, 2018. The DRO approved, without modification, a stipulation and recommendation previously filed by DP&L, along with various intervening parties and the PUCO staff. The DRO established a revenue requirement of $248.0 million for DP&L's electric service base distribution rates which reflects an increase to distribution revenues of approximately $29.8 million per year. In addition to the increase in base distribution rates, among other matters, the DRO also provides for a return on equity of 9.999% and a cost of long-term debt of 4.8%.
For
more information regarding DP&L's ESP and DRO, see Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements.
In December 2018, DP&L filed a Distribution Modernization Plan (“DMP”) with the PUCO proposing to invest $576.0 million in capital projects over the next 10 years. There are eight principal components of DP&L’s DMP: 1) Smart Meters, 2) Self-Healing
Grid, 3) Customer Engagement, 4) Enhancing Sustainability and Embracing Innovation. 5) Telecommunications, 6) Physical and Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D.
These initiatives will also allow DP&L to be ready to leverage and integrate Distributed Energy Resources into its grid, including demonstrations of community solar, energy storage, microgrids, as well as Electric Vehicle charging infrastructure. If approved, DP&L will implement a comprehensive grid modernization project that will deliver benefits to customers, society as a whole and to the Company.
On January 22, 2019,
DP&L filed a request with the PUCO for a two-year extension of its DMR through October 2022, in the proposed amount of $199.0 million for each of the two additional years. The request was made pursuant to the PUCO’s October 20, 2017 ESP order, which approved the DMR and had the option for DP&L to file for a two-year extension. The extension request was set at a level expected to reduce debt obligations at both DP&L and DPL and to position DP&L to make capital expenditures to maintain and modernize its electric grid. To that end, DP&L’s DMP investments are contingent upon the PUCO approving the two-year extension of its DMR.
Ohio law and the PUCO rules contain targets relating to renewable energy, peak demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. DP&L is in full compliance with energy efficiency, peak demand reduction and renewable energy targets. DP&L is required to file an energy efficiency portfolio plan to demonstrate how it plans to meet the standards. On June 15, 2017, DP&L filed an energy efficiency portfolio plan for programs in years 2018 through 2020, which was settled and approved by the PUCO on December 20, 2017.
DP&L recovers the costs of its compliance with Ohio energy efficiency and renewable energy standards through separate riders which are reviewed and audited by the PUCO.
The costs associated with providing high voltage transmission service and wholesale electric sales and ancillary services are subject to FERC jurisdiction. While DPL has market-based rate authority for wholesale electric sales, DPL would be required to file an application at FERC under section 101 of Title 18 of the Code of Federal Regulations to change any of its cost-based transmission or ancillary service rates.
As a member of PJM, DP&L
receives revenues from the RTO related to DP&L’s transmission assets and incurs costs associated with its load obligations for retail customers. Ohio law includes a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. DP&L continues to recover non-market-based transmission and ancillary costs through its transmission rider.
DP&L and AES Ohio Generation filed an application before the FERC to adjust their rates with respect to reactive power provided to PJM from their generation units. On March 3, 2017, DP&L, AES Ohio Generation, and certain intervening parties filed an Offer
of Settlement that was approved by the FERC on May 16, 2017. The changes from current reactive power rates were not material. Additionally, the FERC has referred to the FERC’s Office of Enforcement for investigation, an issue regarding reactive power charges under the previously effective rates in light of changes in DP&L’s generation portfolio. Prior to 2017, DP&L's reactive power rates had been last reset in 1998. As of the date of this report, DP&L is unable to predict the ultimate outcome of the investigation. Several other utilities within PJM are also being investigated by FERC’s Office of Enforcement with respect to the same issue of changes in the generation portfolio that occurred in between rate proceedings. In connection with transactions and other matters
discussed above, there have been subsequent reactive power filings made, including filings to reflect: the transfer of generation from DP&L to AES Ohio Generation; the sale of interests in the
Miami Fort and Zimmer stations to subsidiaries of Dynegy; the retirement of Stuart and Killen; and the sale of interests in the Peaker assets to subsidiaries of Kimura Power, LLC.
DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to
a comparable group to determine whether there were significantly excessive earnings during a given calendar year. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows. See Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements.
Ohio Competition
Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier.
DP&L continues to have the exclusive right to provide delivery service in its state-certified territory and the obligation to procure and provide electricity to SSO customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.
As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities were required to join an RTO. DP&L is a member of the PJM RTO. The role of the RTO is to administer a competitive wholesale market for electricity and ensure reliability of the transmission grid. PJM ensures the reliability of the high-voltage electric power system serving more than 50 million people in all or parts of Delaware,
Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid, administers the world’s largest competitive wholesale electricity market and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.
Like other electric utilities and energy marketers, AES Ohio Generation may sell or purchase electric products in the wholesale market. AES Ohio Generation competes with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of AES Ohio Generation to sell this electricity will depend not only on the performance of its generating unit, but also on how AES Ohio Generation’s
prices, terms and conditions compare to those of other suppliers.
ENVIRONMENTAL MATTERS
DPL’s and DP&L's facilities and operations are subject to a wide range of federal, state and local environmental laws, rules and regulations. The environmental issues that may affect us include the following. However, as described further below, as a result of DPL’s retirement of its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations, the planned 2020 retirement of Conesville and our exiting of our generation business, certain of these environmental regulations and laws are now not expected
to have a material impact on DPL with respect to these generating stations.
•
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, the Ohio EPA or other authorities that require or will require substantial reductions in SO2, particulates, mercury, acid gases, NOx, and other air emissions.
•
Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions
of GHGs;
•
Rules and future rules issued by the USEPA, the Ohio EPA or other authorities associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits; and
•
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste.
In addition to imposing continuing compliance obligations, these laws, rules 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 laws, rules and regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we
have not accrued loss contingencies because the risk of loss is not probable, or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows. See Note 11 – Contractual Obligations, Commercial Commitments and Contingencies – "Environmental Matters” of Notes to DPL's Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies – "Environmental Matters" of Notes
to DP&L's Financial Statements for more information regarding environmental risks, laws and regulations and legal proceedings to which we are and may be subject to in the future.
In response to Executive Orders from the U.S. President, the USEPA is currently evaluating various existing regulations to be considered for repeal, replacement, or modification. We cannot predict at this time the likely outcome of the USEPA’s review of these or other existing regulations or what impact it may have on our business.
We have several pending environmental matters associated with our current and previously owned and operated coal-fired generation units. Some of these matters could have material adverse impacts on our results of operations, financial condition or cash flows.
Environmental
Matters Related to Air Quality
As a result of DPL’s decision to retire its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations and the planned 2020 retirement of Conesville, the following environmental matters, regulations and requirements are now not expected to have a material impact on DPL:
•
The CAA and the following regulations
◦
CSAPR
and associated updates;
◦
MATS and any associated regulatory or judicial processes;
◦
NAAQS; and
◦
CPP or a potential replacement rule.
Litigation Involving Co-Owned Stations
As
a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DPL and the other owners of the Stuart generating station are subject to certain specified emission targets related to NOX, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during startups. Given that all of the commitments have been met and with the retirement of the Stuart generating station, DPL and the other owners plan to submit a request for termination of the consent decree.
Notices
of Violation Involving Co-Owned Units
In June 2000, the USEPA issued an NOV to the then DP&L-operated Stuart generating station (co-owned by AES Ohio Generation, Dynegy and AEP Generation) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DPL cannot predict the outcome of this matter.
In January 2015, DP&L received NOVs from the USEPA alleging
violations in opacity at the Stuart and Killen generating stations in 2014. On February 15, 2017, the USEPA issued an NOV alleging violations in opacity at the Stuart generation station in 2016. Operations at both Stuart and Killen have ceased. However, we are currently unable to predict the outcome of these matters.
Notices of Violation Involving Wholly-Owned Stations
On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings EGU, which was closed in 2013, relating to capital projects performed in 2001 involving Unit 3 and
Unit 6. We do not believe that the two projects described in the NOV were modifications subject to NSR. We cannot predict the outcome of this matter.
Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds
As a result of DPL’s decision to retire its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations and the planned 2020 retirement of Conesville; the following environmental matters, regulations and requirements are now not expected to have a material impact on DPL with respect to these generating stations (although certain other requirements related to
water quality, waste disposal and ash ponds are discussed further below):
•
water intake regulations, including those finalized by the USEPA on May 19, 2014;
•
the appeal of the NPDES permit governing the discharge of water from the Stuart Station; and
•
revised
technology-based regulations governing water discharges from steam electric generating facilities, finalized by the USEPA on November 3, 2015 and commonly referred to as the ELG rules.
Clean Water Act – Regulation of Water Discharge
On January 7, 2013, the Ohio EPA issued a final NPDES permit to the Stuart Station which included a compliance schedule for performing a study to justify an alternate thermal limitation or take undefined measures to meet certain temperature limits. On February 1, 2013, DP&L appealed various aspects of the final permit to the Environmental Review Appeals Commission. As a result of DPL’s decision
to retire the Stuart Station we do not expect this to have a material impact on us.
Clean Water Act rules for Selenium
On July 13, 2016, the USEPA published the final updated chronic aquatic life criterion for the pollutant selenium in freshwater per section 304(a) of the CWA. The rule will be implemented after state rulemaking occurs, and requirements will be incorporated into NPDES permits with compliance schedules in some cases. It is too early in the rulemaking process to determine the impact, if any, on our operations, financial position or results of operations.
Regulation of Waste Disposal
In 2002, DP&L and other parties received a special notice that the USEPA considered DP&L
to be a PRP for the clean-up of hazardous substances at a third-party landfill known as the South Dayton Dump (“Landfill”). Several of the parties voluntarily accepted some of the responsibility for contamination at the Landfill and, in May 2010, three of those parties, Hobart Corporation, Kelsey-Hayes Company, and NCR Corporation (“PRP Group”), filed a civil complaint in Ohio federal court (the “District Court”) against DP&L and numerous other defendants, alleging that the defendants contributed to the contamination at the landfill and were liable for contribution to the PRP group for costs associated with the investigation and remediation of the site.
While DP&L was able to get the initial case dismissed, the PRP Group subsequently, in 2013, entered into an additional Administrative Settlement Agreement
and Order on Consent (“ASAOC”) with the USEPA relating to vapor intrusion and again filed suit against DP&L and other defendants. Trial for that issue was scheduled to be held in 2019, but the District Court recently vacated that trial date and it is unknown when it will be rescheduled. Plaintiffs also attempted to add an additional ASAOC they entered into in 2016 pertaining to the investigation and remediation of all hazardous substances present in the Landfill - potentially including undefined areas outside the original dump footprint - to the vapor intrusion trial proceeding. The District Court allowed the claim to be added to the litigation but ruled that the 2016 ASAOC could not be adjudicated until after completion of the remedial investigation feasibility study, which is expected to be complete years after the vapor intrusion trial. While DP&L is unable to
predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on our business, financial condition or results of operations.
Regulation of CCR
On October 19, 2015, a USEPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills and surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. The primary enforcement mechanisms under this regulation would be actions commenced by the states and private lawsuits.
On December 16, 2016, President Obama signed into law the Water Infrastructure Improvements for the Nation Act ("WIN Act"), which includes provisions to implement the
CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. EPA has indicated that they will implement a phased approach to amending the CCR Rule.
On September 13, 2017, the USEPA indicated that it would reconsider certain provisions of the CCR rule in response to two petitions it
received to reconsider the final rule. It is too early to determine whether the CCR rule or any reconsideration of the rule may have a material impact on our business, financial condition or results of operations.
Notice of Violation Involving Co-Owned Units
On September 9, 2011, DP&L received an NOV from the USEPA with respect to its co-owned Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and the Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the CWA NPDES permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has
subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DPL’s results of operations, financial condition or cash flows.
HOW TO CONTACT DPL AND DP&L
DPL is a regional energy company incorporated in 1985 under the laws of Ohio. Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio45432 - telephone 937-259-7215.
DPL’s public internet site is http://www.dplinc.com. DP&L’s public internet site is http://www.dpandl.com. The information on these websites is not incorporated by reference into this report.
Item 1A – Risk Factors
Investors should consider carefully
the following risk factors that could cause our business, operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. These risk factors should be read in conjunction with the other detailed information concerning DPL set forth in the Notes to DPL's Consolidated Financial Statements and concerning DP&L set forth in the Notes to DP&L's Financial Statements in Part II – Item 8 – Financial Statements and Supplementary Data and additional information in Part II – Item 7 – Management’s Discussion and Analysis of Financial
Condition and Results of Operations herein. The risks and uncertainties described below are not the only ones that we face. In light of executing on our plan to exit generation, our generation business and the risks associated with that business have significantly lessened, such as risks associated with operations of generation plants and with greenhouse gas emission requirements.
We may not always be able to recover our costs to deliver electricity to our retail customers. The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO.
In Ohio, retail generation rates are not subject to cost-based regulation, while the transmission and distribution businesses are still regulated. Even though
rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable. On May 1, 2008, SB 221, an Ohio electric energy bill, was adopted that requires all Ohio distribution utilities to file either an ESP or an MRO and established a significantly excessive earnings test for Ohio public utilities that measures a utility’s earnings to determine whether there have been significantly excessive earnings during a given calendar year. There can be no assurance that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs or permitted rates of return. Accordingly, the revenue DP&L receives may or may not match its expenses
at any given time.
Changes in or reinterpretations of, or the unexpected application of the laws, rules, policies and procedures that set or govern electric rates, permitted rates of return, rate structures, operation of a competitive bid structure to supply retail generation service to SSO customers, reliability initiatives, capital expenditures and investments and the recovery of these and other costs on a full or timely basis through rates, power market prices, and the frequency and timing of rate increases, could have a material adverse effect on our results of operations, financial condition and cash flows.
Our increased costs due to renewable energy and energy efficiency requirements may not be fully recoverable in the future.
Ohio law contains annual targets for energy efficiency which began in 2009 and require increasing energy reductions each year compared to a baseline energy usage, up to 22.3% by 2027. Peak demand reduction targets began in 2009 with increases in required percentages each year, up to 7.75% by 2020. The renewable energy standards have increased our costs and are expected to continue to increase (and could materially increase) these costs. DP&L is entitled to recover costs associated with its renewable energy compliance costs, as well as its energy efficiency and demand response programs. If in the future we are unable to timely or fully recover these costs, it could have a material
adverse effect on our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these standards, monetary penalties could apply. These penalties are not permitted to be recovered from customers and significant penalties could have a material adverse effect on our results of operations, financial condition and cash flows. The demand reduction and energy efficiency standards by design result in reduced energy and demand that could have a material adverse effect on our results of operations, financial condition and cash flows.
We may be negatively affected by a lack of growth or a decline in the number of customers.
Customer growth is affected by a number of factors outside our control, such as population changes, job and income growth,
housing starts, new business formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers in our service territory could have a material adverse effect on our results of operations, financial condition and cash flows and may cause us to fail to fully realize anticipated benefits from investments and expenditures.
We are subject to numerous environmental laws, rules and regulations that require capital expenditures, increase our cost of operations, and may expose us to environmental liabilities.
We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the remediation of retired generation and other facilities, storage, handling, use, storage, disposal and transportation of coal combustion
residuals and other materials, some of which may be defined as hazardous materials, the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. Such laws, rules and regulations tend to become stricter over time, and we could also become subject to additional environmental laws, rules and regulations and other requirements in the future. Environmental laws, rules and regulations also require us to comply with inspections and obtain and comply with a wide variety of environmental licenses, permits, inspections and other governmental authorizations. These laws, rules and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and other governmental authorizations from federal, state and local agencies. If we are not able to timely comply with inspections and obtain, maintain or comply with all environmental laws, rules and regulations, and all licenses, permits
and other government authorizations required to operate our business, then our operations could be prevented, delayed or subject to additional costs. A violation of environmental laws, rules, regulations, licenses, permits or other requirements can result in substantial fines, penalties, other sanctions, permit revocation, facility shutdowns, the imposition of stricter environmental standards and controls or other injunctive measures affecting operating assets. In addition, any actual or alleged violation of these laws, rules or regulations and other requirements may require us to expend significant resources to defend against any such actual or alleged violations. DPL owns an undivided interest in one generating station operated by our co-owner. As a non-controlling owner in this generating station, DPL is responsible for its pro rata share of expenditures for complying with
environmental laws, rules, regulations, licenses, permits and other requirements, but has limited control over the compliance measures taken by our co-owner. Under certain environmental laws, we could also be held strictly, jointly and severally responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held liable for human exposure to such hazardous substances or for other environmental damage.
In particular, we are subject to potentially significant remediation expenses, enforcement initiatives, private-party lawsuits and reputational risk associated with CCR. CCR, which consists of bottom ash, fly ash and air pollution control wastes generated at our current and former coal-fired generation plant sites, is currently handled and/or has been handled in the past in the following ways: placement in
onsite CCR ponds; disposal and beneficial use in onsite and offsite permitted, engineered landfills; use in various beneficial use applications, including encapsulated uses and structural fill; and used in permitted offsite mine reclamation. CCR currently remains onsite at several of our facilities, including in CCR ponds. The USEPA's final CCR rule, which became effective in October 2015 and is currently subject to litigation and undergoing revisions by the USEPA, regulates CCR as nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills, impoundments and ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure
requirements
and post-closure care. On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation (WIIN) Act into law, which includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. The primary enforcement mechanisms for the CCR rule could be actions commenced by the USEPA, states and private lawsuits. Compliance with the CCR rule, amendments to the federal CCR rule, or other federal, state, or foreign rules or programs addressing CCR may require us to incur substantial costs. In addition, CCR, particularly with respect to its beneficial use and regulation as nonhazardous solid waste, has been the subject of interest from environmental non-governmental organizations and the media. Any of the foregoing could have a material adverse effect on our results of operations, financial
condition and cash flows.
From time to time we are subject to enforcement and litigation actions for claims of noncompliance with environmental laws, rules and regulations or other environmental requirements. DPL cannot assure that it will be successful in defending against any claim of noncompliance. Any actual or alleged violation of these laws, rules, regulations and other requirements may require us to expend significant resources to defend against any such actual or alleged violations and expose us to unexpected costs. Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows. See Item 1 - Business - Environmental Matters for a more comprehensive discussion
of these and other environmental matters impacting us.
We are reliant upon the performance of a co-owner who operates our remaining co-owned operational EGU.
We co-own an EGU operated by one of our co-owners. Poor operational performance by our co-owner, misalignment of co-owners’ interests with our own or lack of control over costs (such as fuel costs) incurred at this station could have an adverse effect on us. In addition, any sale of this co-owned EGU by the co-owner to a third party could enhance the risk of a misalignment of interests, lack of cost control and other operational failures.
The use of non-derivative and derivative instruments in the normal course of business could result in losses that could negatively impact our results of
operations, financial position and cash flows.
From time to time, we use non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage financial risks. These trades are affected by a range of factors, including fluctuations in interest rates and optimization opportunities. We have attempted to manage our risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect
the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts, a counterparty failing to perform or the underlying transactions which the instruments are intended to hedge failing to materialize, which could result in a material adverse effect on our results of operations, financial condition and cash flows.
The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.
In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among
others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
Our
business is sensitive to weather and seasonal variations.
Weather conditions significantly affect the demand for electric power and, accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our operating revenues and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may
require
us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.
On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions
and fully integrated into PJM, a regional transmission organization.
The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. Various proposals and proceedings before the FERC may cause transmission rates to change from time to time. In addition, PJM developed and continues to refine rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial effect on us. We also incur fees and costs to participate in PJM.
SB
221 includes a provision that allows electric utilities to seek and obtain recovery of RTO-related charges. Therefore, non-market-based costs are being recovered from all retail customers through the transmission rider. If in the future, however, we are unable to recover all of these costs in a timely manner this could have a material adverse effect on our results of operations, financial condition and cash flows.
As members of PJM, DP&L and AES Ohio Generation are also subject to certain additional risks including those associated with the allocation of losses caused by unreimbursed defaults of other participants in PJM markets among PJM members and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L
and AES Ohio Generation. These amounts could be significant and have a material adverse effect on our results of operations, financial condition and cash flows.
Costs associated with new transmission projects could have a material adverse effect on our results of operations, financial condition and cash flows.
Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. Over the last several years, however, some of the costs of constructing new large transmission facilities have been “socialized” across PJM without a direct relationship between the costs assigned to and benefits
received by particular PJM members. To date, the additional costs charged to DP&L for new large transmission approved projects have not been material. Over time, as more new transmission projects are constructed and if the allocation method is not changed, the annual costs could become material. DP&L is recovering the Ohio retail jurisdictional share of these allocated costs from its retail customers through the transmission rider. To the extent that any costs in the future are material and we are unable to recover them from our customers, such costs could have a material adverse effect on our results of operations, financial condition and cash flows.
If we were found not to be in compliance with the mandatory reliability standards,
we could be subject to sanctions, including substantial monetary penalties.
As an owner of a bulk power transmission system, DP&L is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. In addition, DP&L is subject to Ohio reliability standards and targets. Compliance with reliability standards may subject us to higher operating costs or increased capital expenditures. Although we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCO will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability
standards, we could be subject to sanctions, including substantial monetary penalties, which could have a material adverse effect on our results of operations, financial condition and cash flows.
We rely on access to the financial markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms, or at all, and cause increases in our interest expense.
From time to time we rely on access to the capital and credit markets as a source of liquidity
for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time and the ability of corporations to raise capital can be negatively affected. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. It is possible that our ability to raise capital on favorable terms, or at all, could be adversely affected by future market conditions, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, financial condition and prospects, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing, the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances and other general economic and
business conditions. It may also depend on the performance of credit counterparties and financial institutions with which we do business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability. See Note 7 – Long-term debt of Notes to DPL's Consolidated Financial Statements and Note 7 – Long-term debt
of Notes to DP&L's Financial Statements for information regarding indebtedness. See also Item 7A - Quantitative and Qualitative Disclosure about Market Risk for information related to market risks.
Our transmission and distribution system is subject to operational, reliability and capacity risks.
The ongoing reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, equipment or process failure, catastrophic events, such as fires and/or explosions, facility outages, labor disputes, accidents or injuries, operator error or inoperability of key infrastructure internal or external to us and events
occurring on third party systems that interconnect to and affect our system. The failure of our transmission and distribution system to fully operate and deliver the energy demanded by customers could have a material adverse effect on our results of operations, financial condition and cash flows, and if such failures occur frequently and/or for extended periods of time, could result in adverse regulatory action. In addition, the advent and quick adoption of new products and services that require increased levels of electrical energy cannot be predicted and could result in insufficient transmission and distribution system capacity. Also, as a result of the above risks and other potential risks and hazards associated with transmission and distribution operations, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. We maintain an amount of insurance protection that we believe is adequate, but there can
be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Further, any increased costs or adverse changes in the insurance markets may cause delays or inability in maintaining insurance coverage on terms similar to those presently available to us or at all. A successful claim for which we are not fully insured could have a material adverse effect on our results of operations, financial condition and cash flows.
Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties, which may adversely affect our results of operations, financial condition and cash flows.
Our business, results of operations, financial condition and cash flows have been
and will continue to be affected by general economic conditions. Slowing economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in a normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns,
our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic conditions improve. Some of our suppliers, customers, other counterparties and others with whom we transact business may also experience financial difficulties, which may impact their ability to fulfill their obligations to us or result in their declaring bankruptcy or similar insolvency-type proceedings. For example, our counterparties on
forward purchase contracts and financial institutions involved
in our credit facility may become unable to fulfill their contractual obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, the projected economic growth and total employment in DP&L’s service territory are important to the realization of our forecasts for annual energy sales.
The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility, and a material change in market interest rates could adversely
affect our results of operations, financial condition and cash flows.
As of December 31, 2018, the carrying value of DPL's debt was $1,475.9 million and the carrying value of DP&L's debt was $586.1 million. Of DP&L's indebtedness, there was $576.1 million of First Mortgage Bonds, tax-exempt bonds and a term loan outstanding as of December 31, 2018, which are each secured by the pledge of substantially all of the assets of DP&L
under the terms of DP&L’s First & Refunding Mortgage. This level of indebtedness and related security could have important consequences, including:
•
increasing our vulnerability to general adverse economic and industry conditions;
•
requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;
•
limiting
our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
•
limiting, along with the financial and other restrictive covenants in our indebtedness, our ability to borrow additional funds, as needed.
If DP&L issues additional debt in the future, we will be subject to the terms of such debt agreements and be required to obtain regulatory approvals. To the extent we increase our leverage, the risks described above would also increase. Further, actual cash requirements in the future may be greater than expected. Accordingly, our cash flows
from operations may not be sufficient to repay all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms, or at all, to refinance our debt as it becomes due. For a further discussion of our outstanding debt obligations, see Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition, Liquidity and Capital Requirements and Note 7 – Long-term debt of Notes to DPL's Consolidated Financial Statements and Note 7 – Long-term debt of Notes to DP&L's Financial Statements.
DP&L
has variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, rating agencies issue ratings on our credit and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Credit ratings also govern the collateral provisions of certain of our contracts. If the rating agencies were to downgrade our credit ratings further, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we
could be required to post additional collateral under select contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
Economic conditions relating to the asset performance and interest rates of our pension and postemployment benefit plans could materially and adversely impact our results of operations, financial condition and cash flows.
Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions
could prove to be wrong, resulting in a shortfall of our pension and postemployment benefit plan assets compared to obligations under our pension and postemployment benefit plans. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postemployment benefit plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postemployment benefit plan assets will increase the funding requirements under our pension and postemployment benefit plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding
requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our pension and postemployment benefit plans’ assets compared to obligations under the pension and postemployment benefit plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. When interest rates decrease, the discounted liabilities
increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.
Counterparties providing materials or services may fail to perform their obligations, which could harm our results of operations, financial condition and cash flows.
We enter into transactions with and rely on many counterparties in connection with our business, including for purchased power, for our capital improvements and additions and
to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.
Further, from time to time our construction program may call for extensive expenditures for capital improvements and additions, including the installation of upgrades, improvements to transmission and distribution facilities, as well as other initiatives. As a result, we may engage contractors and enter into agreements to acquire necessary materials and/or obtain required construction related services. In addition, some contracts may provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause construction delays. It could also subject us to enforcement action by regulatory authorities to the extent that such a contractor failure resulted in a failure by DP&L
to comply with requirements or expectations, particularly with regard to the cost of the project. If these events were to occur, we might incur losses or delays in completing construction.
Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure or incorrect payment processing.
Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP in the United States of America, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the
recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations,
financial condition and cash flows.
New accounting standards or changes to existing accounting standards could materially affect how we report our results of operations, financial condition and cash flows.
DPL's Consolidated Financial Statements and DP&L's Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be
difficult to predict and could materially affect how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our Financial Statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.
We are subject to extensive laws and local, state and federal regulation, as well as litigation and other proceedings that could affect our operations and costs.
As an electric utility, DP&L is subject to extensive regulation at both the federal and state level. For example, at the federal
level, DP&L is regulated by the FERC and the NERC and, at the state level, by the PUCO. The regulatory power of the PUCO over DP&L is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Ohio. DP&L is subject to regulation by the PUCO as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of securities and incurrence of debt, the acquisition and sale of some public utility properties or securities and certain other matters. As a result of the Energy Policy Act
of 2005 and subsequent legislation affecting the electric utility industry, we have been required to comply with rules and regulations in areas including mandatory reliability standards, cybersecurity, transmission expansion and energy efficiency. Complying with the regulatory environment to which we are subject requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business that could have a material adverse effect on our results of operations, financial condition and cash flows.
We may be subject to material litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time which
may require us to expend significant funds to address. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition and cash flows. Asbestos and other regulated substances are, and may continue to be, present at our facilities, and we have been named as a defendant in asbestos litigation. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. See Item 1 - Business - Competition and Regulation, Item 1 - Business - Environmental Matters, and Item 3 - Legal Proceedings for a summary of significant regulatory matters and legal proceedings involving us.
Tax
legislation initiatives or challenges to our tax positions could adversely affect our operations and financial condition.
We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures.
For example, the United States federal government recently enacted tax reform that, among other things, reduces U.S. federal corporate income tax rates, imposes limits on tax deductions for interest expense and changes the rules related to capital expenditure cost recovery. There are a number of uncertainties and ambiguities as to the interpretation and
application of many of the provisions of the newly enacted tax reform measure. Given the unpredictability of these possible changes and their potential interdependency, it remains difficult to assess the overall effect such tax changes will have on our earnings and cash flow, and the extent to which such changes could adversely impact our results of operations. As the impacts of the new law are determined, and as yet-to-be-released regulations and other guidance interpreting the new law are issued and finalized, our financial results could be materially impacted.
In addition, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material adverse effect
on our results of operations, financial condition and cash flows.
If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.
One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could
require us to make additional
financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We may not be able to successfully train new personnel as current workers with significant knowledge and expertise retire. We also may be unable to staff our business with qualified personnel in the event of significant absenteeism related to a pandemic illness. Excessive risk-taking by our employees to achieve performance targets, through mitigated by policies and procedures, could result in events that have a material adverse effect on our results of operations,
financial condition and cash flows.
We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements with employees who are members of a union. Over half of our employees are represented by a collective bargaining agreement that expires on October 31, 2020. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreement or at the expiration of the collective bargaining agreement before a new agreement is negotiated. Work
stoppages by, or poor relations or ineffective negotiations with, our employees or other workforce issues could have a material adverse effect on our results of operations, financial condition and cash flows.
Potential security breaches (including cybersecurity breaches) and terrorism risks could adversely affect our businesses.
We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation stations, fuel storage facilities and transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes. In particular, given the
importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war. We have implemented measures to help prevent unauthorized access to our systems and facilities, including network and system monitoring, identification and deployment of secure technologies, and certain other measures to comply with mandatory regulatory reliability standards. Pursuant to NERC requirements, we have a robust cybersecurity plan in place and are subject to regular audits by an independent auditor approved by the NERC. We routinely test our systems and facilities against these regulatory requirements in order to measure compliance, assess potential security risks, and identify areas for improvement. In addition, we provide cybersecurity training for our employees and perform exercises designed to raise employee awareness of cyber risks on a regular basis. To date, cyber-attacks on our business and operations have
not had a material impact on our operations or financial results. Despite these efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely manner to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenues and increases in costs that could have a material adverse effect on our results of operations, financial condition and cash flows.
In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information, including personally identifiable information and personal financial information. If our or our third-party vendors’ systems were to be breached or disabled, sensitive and confidential information and other data
could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.
To help mitigate these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.
DPL is a holding company and parent of DP&L and other subsidiaries. DPL’s cash flow is dependent on the operating cash flows of DP&L and its other subsidiaries and their ability to pay cash to DPL.
DPL is a holding company with no material assets other than the ownership of its subsidiaries,
and accordingly all cash is generated by the operating activities of its subsidiaries, principally DP&L. As such, DPL’s cash flow is largely dependent on the operating cash flows of DP&L and its ability to pay cash to DPL. See Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity for a discussion of these restrictions. See Note 7 – Long-term debt of Notes to DPL's Consolidated
Financial Statements and Note 7 – Long-term debt of Notes to DP&L's Financial Statements for information regarding indebtedness. In addition, DP&L is regulated by the PUCO, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The PUCO could impose additional restrictions on the ability of DP&L to distribute, loan or advance cash to DPL pursuant to these broad powers. See Note 3 – Regulatory Matters of Notes to DPL's Consolidated
Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements for more information the regulatory environment. As part of the PUCO’s approval of the Merger, DP&L agreed to maintain certain capital structure levels. See Note 10 – Equity of Notes to DPL's Consolidated Financial Statements and Note 10 – Equity of Notes to DP&L's Financial Statements for information related to these capital structure levels and restrictions on DP&L's
equity and its ability to declare and pay dividends to DPL. While we do not expect any of the foregoing to significantly affect DP&L’s ability to pay funds to DPL in the near future, a significant limitation on DP&L’s ability to pay dividends or loan or advance funds to DPL could have a material adverse effect on DPL’s results of operations, financial condition and cash flows. In addition, as a result of any non-compliance with PUCO requirements, the PUCO could impose additional restrictions on DP&L operations that could have a
material adverse effect on our results of operations, financial condition and cash flows.
Our ownership by AES subjects us to potential risks that are beyond our control.
All of DP&L’s common stock is owned by DPL, and DPL is an indirectly wholly owned subsidiary of AES. Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in DPL’s or DP&L’s credit ratings being downgraded.
Impairment
of long-lived assets would negatively affect our consolidated results of operations and net worth.
Long-lived assets are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present. The recoverability assessment of long-lived assets requires making estimates and assumptions to determine fair value, as described above. See Note 17 – Fixed-asset impairments or Notes to DPL's Consolidated Financial Statements for more information on the impairment of fixed assets.
Item
1B – Unresolved Staff Comments
None.
Item 2 – Properties
Information relating to our properties is contained in Note 4 – Property, Plant and Equipment of Notes to DPL's Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L's Financial
Statements.
Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio. This facility and the remainder of our material properties are owned directly by DP&L or AES Ohio Generation. These properties include our distribution service center in Dayton, Ohio, various substations and other transmission and distribution equipment and property.
Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. All generation assets were released from the lien of DP&L's first and refunding mortgage
in connection with the completion of Generation Separation on October 1, 2017. See Note 14 – Generation Separation of Notes to DP&L's Financial Statements.
Item 3 – Legal Proceedings
DPL and DP&L are involved in certain claims, suits and legal proceedings in the
normal course of business. DPL and DP&L have accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. DPL and DP&L believe, based upon information they currently possess and considering established reserves for estimated liabilities and insurance coverage, that the ultimate
outcome of these proceedings and actions is unlikely to have a material adverse effect on their financial statements.
It is reasonably possible, however, that some matters could be decided unfavorably and could require DPL or DP&L to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2018.
The following additional information is incorporated by reference into this Item: information about the legal proceedings contained in Item 1 - Business - Competition and Regulation and Item 1 - Business - Environmental Matters.
Item 5 – Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
All
of the outstanding common stock of DPL is owned indirectly by AES and directly by a wholly-owned subsidiary of AES. As a result, DPL’s stock is not listed for trading on any stock exchange. DP&L’s common stock is held solely by DPL and, as a result, is not listed for trading on any stock exchange.
Dividends and return of capital
During the years ended December 31, 2018, 2017 and 2016, DPL paid no dividends to AES. DP&L
declares and pays dividends on its common shares to its parent DPL from time to time as declared by the DP&L board. Return of capital payments and dividends on common shares in the amounts of $43.8 million, $39.0 million and $70.0 million were declared and paid in the years ended December 31, 2018, 2017 and 2016, respectively. DP&L declared and paid dividends on preferred shares of $0.7 million in the year ended December 31, 2016.
DPL’s
Amended Articles of Incorporation contain restrictions on DPL’s ability to make dividends, distributions and affiliate loans (other than to its subsidiaries), including restrictions on making such dividends, distributions and loans if certain financial ratios exceed specified levels and DPL’s senior long-term debt rating from a rating agency is below investment grade. As of December 31, 2018, DPL’s leverage ratio was at 1.47 to 1.00 and DPL’s senior long-term debt rating from a major credit rating agency was below investment grade. As a result, as of December 31, 2018,
DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).
DP&L's 2017 ESP also contains restrictions on dividend or tax sharing payments from DPL to AES. See Note 10 – Equity for more information and Note 8 – Income Taxes for more information about the tax sharing payment restrictions.
On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L
redeemed all of its issued and outstanding preferred stock. See Note 10 – Equity of Notes to DPL's Consolidated Financial Statements for more information and Note 10 – Equity of Notes to DP&L's Financial Statements.
The following table presents our selected financial data which should be read in conjunction with DPL's audited Consolidated Financial Statements and the related Notes thereto, DP&L's audited Financial Statements and the related Notes thereto and Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations. The “Results of Operations” discussion in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations addresses significant fluctuations in operating data. DPL’s common stock is wholly-owned by an indirect subsidiary of AES and therefore DPL does not report earnings or dividends on a per-share basis. Other
information that management believes is important in understanding trends in our business is also included in this table. The total electric sales and Statements of Operations Data for DPL for 2014 and 2015 and the Balance Sheet Data for DPL for 2014 - 2016 are not comparable to the total electric sales and Statements of Operations Data for 2016 - 2018 and the Balance Sheet Data for 2017 and 2018, respectively, as these periods have not been adjusted to reflect the reclassification of the generation business, excluding Conesville, as a discontinued operation. The Statements of Operations Data for DP&L for 2014 and the total electric sales and Balance Sheet Data for DP&L for 2014 - 2015 are not comparable to the Statements of Operations Data for 2015 - 2018 and the total electric
sales and Balance Sheet Data for 2016 - 2018, respectively, as these periods have not been adjusted to reflect the Generation Separation and its reclassification as a discontinued operation.
DPL
Years
ended December 31,
$ in millions except per share amounts or as indicated
2018
2017
2016
2015
2014
Total electric sales (millions of kWh)
15,728
14,679
15,406
20,756
19,060
Statements
of Operations Data
Revenues
$
775.9
$
743.9
$
834.2
$
1,612.8
$
1,716.5
Goodwill
impairment (a)
$
—
$
—
$
—
$
317.0
$
—
Fixed-asset
impairment (b)
$
2.8
$
—
$
23.9
$
—
$
11.5
Operating
income / (loss)
$
135.5
$
105.2
$
119.0
$
(109.9
)
$
230.7
Income
/ (loss) from continuing operations
$
31.2
$
(1.5
)
$
14.8
$
(251.4
)
$
57.2
Income
/ (loss) from discontinued operations, net of tax
$
38.9
$
(93.1
)
$
(500.0
)
$
12.4
$
(131.8
)
Net
income / (loss)
$
70.1
$
(94.6
)
$
(485.2
)
$
(239.0
)
$
(74.6
)
Capital
expenditures
$
103.6
$
121.5
$
148.5
$
137.2
$
118.1
Balance
Sheet Data (end of period):
Total assets
$
1,883.1
$
2,049.2
$
2,419.2
$
3,324.7
$
3,559.1
Long-term
debt (c)
$
1,372.3
$
1,700.2
$
1,828.7
$
1,420.5
$
2,120.9
Redeemable
preferred stock of subsidiary
$
—
$
—
$
—
$
18.4
$
18.4
Total
common shareholder's equity / (deficit)
$
(471.7
)
$
(584.3
)
$
(587.6
)
$
(80.6
)
$
148.2
(a)
The
goodwill impairment of $135.8 million in 2014 related to DPLER has been reclassified to discontinued operations.
(b)
Fixed-asset impairments of $175.8 million and $835.2 million in 2017 and 2016, respectively, have been reclassified to discontinued operations.
(c)
Excluded from this line are the current maturities of long-term debt.
DP&L
Years
ended December 31,
$ in millions except per share amounts or as indicated
2018
2017
2016
2015
2014
Total electric sales (millions of kWh)
15,194
14,401
15,008
26,394
28,634
Statements
of Operations Data
Revenues
$
738.7
$
720.0
$
808.0
$
857.0
$
1,668.3
Fixed-asset
impairment (a)
$
—
$
—
$
—
$
—
$
—
Operating
income
$
135.1
$
122.1
$
169.0
$
222.2
$
188.8
Income
from continuing operations
$
86.7
$
57.4
$
97.6
$
130.0
$
114.1
Loss
from discontinued operations, net of tax
$
—
$
(40.4
)
$
(870.3
)
$
(23.6
)
$
—
Net
income / (loss) attributable to common stock
$
86.7
$
17.0
$
(773.4
)
$
105.5
$
114.1
Capital
expenditures
$
93.1
$
101.7
$
128.3
$
127.0
$
114.2
Balance
Sheet Data (end of period):
Total assets
$
1,819.6
$
1,695.9
$
2,035.1
$
3,359.6
$
3,328.8
Long-term
debt (b)
$
581.5
$
642.0
$
731.5
$
313.6
$
868.2
Redeemable
preferred stock
$
—
$
—
$
—
$
22.9
$
22.9
Total
common shareholder's equity
$
445.3
$
330.7
$
362.3
$
1,212.7
$
1,143.4
Number
of shareholders - preferred stock
—
—
—
180
186
(a)
Fixed-asset
impairment of $1,353.5 million in 2016 has been reclassified to discontinued operations.
(b)
Excluded from this line are the current maturities of long-term debt.
Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations
The
following discussion and analysis should be read in conjunction with DPL’s audited Consolidated Financial Statements and the related Notes thereto and DP&L’s audited Financial Statements and the related Notes thereto included in Item 8 – Financial Statements and Supplementary Data of this Form 10-K. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. See “Forward-Looking Statements” at the beginning of this Form 10-K and Item 1A – Risk Factors. For a list of certain abbreviations or acronyms in this discussion, see Glossary of Terms at the beginning of this Form 10-K.
EXECUTIVE
SUMMARY
DPL
DPL's income / (loss) from continuing operations before income tax for the year ended December 31, 2018 improved by $38.4 million, or 591%, from a pre-tax loss of $6.5 million for the year ended December 31, 2017 to pre-tax income of $31.9
million for the year ended December 31, 2018, primarily due to factors including, but not limited to:
$ in millions
2018 vs. 2017
Favorable impact of DMR rider following 2017 ESP
$
28.0
Higher
rates from DRO
9.9
Higher retail revenue volumes driven by favorable weather
31.9
Lower interest expense due to debt payments made in 2017 and 2018
12.0
Decrease
due to higher purchased power volumes, driven by higher retail demand
(25.7
)
Loss on transfer of Beckjord facility
(11.7
)
Other
(6.0
)
Net change
in income / (loss) from continuing operations before income tax
$
38.4
DPL's income / (loss) from continuing operations before income tax for the year ended December 31, 2017 declined by $18.9 million, or 152%, from pre-tax income of $12.4
million for the year ended December 31, 2016 to a pre-tax loss of $6.5 million for the year ended December 31, 2017, primarily due to factors including, but not limited to:
$ in millions
2017 vs. 2016
Decrease
from reverting to ESP 1 rates in September 2016, partially offset by the implementation of the DMR in November 2017
$
(22.0
)
Lower retail revenue volumes driven by unfavorable weather
(28.4
)
Increase due to lower purchased power volumes, driven by lower retail demand
6.7
Fixed
asset impairment recorded in 2016 on Conesville facility
23.9
Other
0.9
Net change in income / (loss) from continuing operations before income tax
$
(18.9
)
DP&L
DP&L's
income from continuing operations before income tax for the year ended December 31, 2018 improved by $15.9 million, or 18%, from pre-tax income of $88.5 million for the year ended December 31, 2017 to pre-tax income of $104.4 million for the year ended December 31, 2018, primarily due to factors including, but not limited to:
$
in millions
2018 vs. 2017
Favorable impact of DMR rider following 2017 ESP
$
28.0
Higher rates from DRO
9.9
Higher retail revenue volumes driven by favorable
weather
31.7
Decrease due to higher purchased power volumes, driven by higher retail demand
(24.6
)
Loss on transfer of Beckjord facility
(12.4
)
Increase
in legal and other consulting costs, including write-off of previously deferred rate case costs no longer deemed probable for recovery
(8.1
)
Increase in insurance and claims costs
(4.0
)
Other
(4.6
)
Net
change in income from continuing operations before income tax
DP&L's income from continuing operations before income tax for the year ended December 31, 2017
declined $55.1 million, or 38%, from pre-tax income of $143.6 million for the year ended December 31, 2016 to a pre-tax income of $88.5 million for the year ended December 31, 2017 primarily due to factors including, but not limited to:
$
in millions
2017 vs. 2016
Decrease from reverting to ESP 1 rates in September 2016, partially offset by the implementation of the DMR in November 2017
$
(22.0
)
Lower retail revenue volumes driven by unfavorable weather
(28.5
)
Increase
in General taxes driven by higher property taxes
(8.3
)
Lower purchased power volumes, driven by lower retail demand
7.9
Other
(4.2
)
Net change
in income from continuing operations before income tax
$
(55.1
)
RESULTS OF OPERATIONS – DPL
DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific
discussion of the results of operations for DP&L is presented elsewhere in this report.
Statement of Operations Highlights – DPL
Years ended December 31,
$ in millions
2018
2017
2016
Revenues:
Retail
$
656.9
$
641.5
$
738.5
Wholesale
52.0
31.9
27.1
RTO
revenue
43.2
47.4
46.5
RTO capacity revenues
14.4
12.1
11.0
Other
revenues
9.4
11.0
11.1
Total revenues
775.9
743.9
834.2
Cost
of revenues:
Net fuel cost
17.5
9.0
17.4
Purchased
power:
Purchased power
244.9
231.4
258.1
RTO
charges
57.8
57.5
59.7
RTO capacity charges
2.3
2.1
1.3
Net
purchased power cost
305.0
291.0
319.1
Total
cost of revenues
322.5
300.0
336.5
Gross
margin
453.4
443.9
497.7
Operating
expenses:
Operation and maintenance
156.8
186.1
213.5
Depreciation
and amortization
73.1
76.1
73.6
General taxes
73.5
77.1
68.4
Fixed-asset
impairment
2.8
—
23.9
Gain on asset disposal
—
(0.6
)
(0.7
)
Loss
on disposal of business (Note 16)
11.7
—
—
Total operating expenses
317.9
338.7
378.7
Operating
income
135.5
105.2
119.0
Other
expense, net
Interest expense
(98.0
)
(110.0
)
(107.4
)
Charge
for early redemption of debt
(6.5
)
(3.3
)
(3.1
)
Other income
0.9
1.6
3.9
Other
expense, net
(103.6
)
(111.7
)
(106.6
)
Income
/ (loss) from continuing operations before income tax (a)
$
31.9
$
(6.5
)
$
12.4
(a)
For
purposes of discussing operating results, we present and discuss Income / (loss) from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore,
our retail sales volume is affected by the number of heating and cooling degree-days occurring during a year. Cooling degree-days typically have a more significant effect than heating degree-days since some residential customers do not use electricity to heat their homes.
Heating
and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25-degree difference between 65 degrees and 40 degrees. Similarly, cooling degrees in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.
DPL's electric sales and billed customers were as follows:
DPL retail electric sales represent the total transmission and distribution retail sales for the periods presented. SSO sales were 3,977 KWh, 3,684 KWh and 3,856 KWh for the years ended December 31, 2018, 2017 and 2016, respectively.
(c)
Included within DPL
wholesale electric sales are DP&L's 4.9% share of the generation output of OVEC and the generation output of Conesville.
During the year ended December 31, 2018, Revenues increased $32.0 million to $775.9 million from $743.9 million in the same period of the prior year. This increase was a result of:
$
in millions
2018 vs. 2017
Retail
Rate
Decrease in energy efficiency and USF revenue rate riders
$
(46.6
)
Decrease
in competitive bid revenue rate rider
(12.5
)
Increase due to implementation of the DMR in November 2017
28.0
Increase due to DRO
9.9
Other
4.7
Net
change in retail rate
(16.5
)
Volume
Increase due to favorable weather, as shown above by the 51% increase in cooling degree-days and 15% increase in heating degree-days
31.9
Total
retail change
15.4
Wholesale
Increase due to increased volumes sold by Conesville of 93% and higher wholesale prices and increased volumes for DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at
market prices
During the year ended December 31, 2017, Revenues decreased $90.3 million to $743.9 million from $834.2 million in the same period of the prior year. This decrease was a result of:
$ in millions
2017
vs. 2016
Retail
Rate
Decrease in energy efficiency and USF revenue rate riders
$
(29.6
)
Decrease in competitive bid revenue rate rider
(22.0
)
Decrease
from reverting to ESP 1 rates in September 2016, offset by the implementation of the DMR in November 2017
(22.3
)
Other
4.7
Net change in retail rate
(69.2
)
Volume
Decrease
due to unfavorable weather, as shown above by the 27% decrease in cooling degree-days and 5% decrease in heating degree-days
(28.4
)
Other miscellaneous
0.6
Total retail change
(97.0
)
Wholesale
Wholesale
revenues
Increase due to higher wholesale prices for DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at market prices, and an increase in the load served of other parties through their competitive bid process, partially offset by decreased volumes sold by Conesville of 30% and decreased wholesale volumes for OVEC
4.8
RTO
revenues and RTO capacity revenues
RTO revenues and RTO capacity revenues
2.0
Other
Other
revenues
(0.1
)
Net change in Revenues
$
(90.3
)
DPL – Cost of Revenues
During
the year ended December 31, 2018, Cost of revenues increased $22.5 million compared to the prior year. This increase was a result of:
$ in millions
2018 vs. 2017
Fuel
Net
fuel costs
Increase due to higher internal generation at Conesville of 93%
$
8.5
Net purchased power
Purchased
power
Rate
Decrease due to lower rates in the competitive bid process
(12.2
)
Volume
Increase
due to higher competitive bid purchases due to increased DP&L retail demand
During the year ended December 31, 2017, Cost of revenues decreased $36.5 million compared to the prior year. This decrease was a result of:
$ in millions
2017 vs. 2016
Fuel
Net
fuel costs
Decrease due to fuel costs deferred in 2015 being collected in 2016, and decreased internal generation at Conesville of 30%
$
(8.4
)
Net purchased power
Purchased
power
Rate
Decrease due to lower rates in the competitive bid process
(20.0
)
Volume
Decrease
due to fewer competitive bid purchases due to decreased DP&L retail demand
(6.7
)
Total purchased power change
(26.7
)
RTO charges
Decrease due to lower transmission
and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within DP&L's network, which are incurred and charged to customers in the transmission rider
(2.2
)
RTO capacity charges
0.8
Net change in purchased power
(28.1
)
Net
change in Cost of Revenues
$
(36.5
)
DPL - Operation and Maintenance
During the year ended December 31, 2018, Operation and Maintenance expense decreased $29.3 million compared to the prior year. This decrease was a result of:
$
in millions
2018 vs. 2017
Decrease in alternative energy and energy efficiency programs (a)
$
(34.2
)
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
(8.5
)
Decrease
due to higher severance expense in the prior year mostly due to AES restructuring activities
(2.6
)
Decrease in group insurance expense associated with participation in the AES self-insurance plan
(2.2
)
Increase in amortization of previously deferred regulatory costs, including rate case costs, certain transmission costs, and various costs collected under the regulatory compliance rider (a)
10.8
Increase
in legal and other consulting costs, including write-off of previously deferred rate case costs no longer deemed probable for recovery
7.3
Increase in maintenance of overhead transmission and distribution lines
2.6
Other, net
(2.5
)
Net
change in Operations and Maintenance expense
$
(29.3
)
(a)
There is corresponding revenue associated with these program costs resulting in minimal impact to Net income.
During the year ended December 31, 2017, Operation and Maintenance
expense decreased $27.4 million compared to the prior year. This decrease was a result of:
$ in millions
2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
$
(24.0
)
Decrease
in alternative energy and energy efficiency programs (a)
(6.6
)
Increase in group insurance expense associated with participation in the AES self-insurance plan
3.3
Increase in legal and other consulting costs
2.9
Other,
net
(3.0
)
Net change in Operation and Maintenance expense
$
(27.4
)
(a)
There is corresponding revenue associated with these program costs resulting in
minimal impact to Net income.
DPL – Depreciation and Amortization
During the year ended December 31, 2018, Depreciation and amortization expense decreased $3.0 million compared to the prior year. The decrease was primarily due to a credit recorded in the fourth quarter of 2018 related to the reduction of ARO assets for Conesville. The ARO assets were previously fully impaired.
During the year ended December 31, 2017, Depreciation and amortization
expense increased $2.5 million compared to the prior year. The increase was primarily due to additional investments in transmission and distribution fixed assets.
During the year ended December 31, 2018, General taxes decreased $3.6 million compared to the prior year. The decrease was primarily the result of a favorable adjustment for 2017
Ohio property taxes to reflect actual payments made in 2018 and the unfavorable true-up of $1.1 million in 2017 for the 2016 Ohio property taxes.
During the year ended December 31, 2017, General taxes increased $8.7 million compared to the prior year. The increase was primarily the result of an increase of $3.8 million in Ohio property tax expense driven by higher tax rates and higher property values, against lower expense in 2016 due to a $2.4 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016, an unfavorable true-up of $1.1 million in 2017 for the 2016 Ohio property tax accrual to reflect actual payments made in 2017 and a $1.4 million increase in other general taxes.
DPL
– Fixed-asset Impairments
During the year ended December 31, 2018, DPL recorded an impairment of fixed assets of $2.8 million for Conesville, as it was determined that its carrying amount was not recoverable.
During the year ended December 31, 2016, DPL recorded an impairment of fixed assets of $23.9 million. In the fourth quarter of 2016, DPL performed a long-lived asset impairment analysis for Conesville and determined that its carrying amount was not recoverable.
DPL
– Loss on Disposal of Business
During the year ended December 31, 2018, DPL recorded a loss on disposal of business of $11.7 million due to the loss on the transfer of business interests in the Beckjord facility.
DPL – Interest Expense
During the year ended December 31, 2018, Interest expense decreased $12.0 million compared to the prior year. The decrease was primarily the result of debt repayments at DPL and DP&L in
2017 and 2018.
During the year ended December 31, 2017, Interest expense increased $2.6 million compared to the prior year primarily due to higher interest rates. On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds Due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%.
DPL
– Charge for Early Redemption of Debt
During the year ended December 31, 2018, DPL recorded a charge for early redemption of debt of $6.5 million primarily due to the make-whole premium payment of $5.1 million related to the $101.0 million partial redemption, in April 2018, of the DPL 6.75% Senior Notes due 2019.
During the year ended December 31, 2017, DPL recorded a charge for early redemption of debt of
$3.3 million primarily due to the early
redemption of the 4.8% Tax-exempt First Mortgage Bonds due 2036.
During the year ended December 31, 2016, DPL recorded a charge for early redemption of debt of $3.1 million primarily due to the February 2016 make-whole premium of $2.4 million associated with the early retirement of $73.0 million of the 6.5% Senior Notes due in 2016.
DPL – Income Tax Expense
Income tax benefit of $5.0 million in 2017 changed to expense of $0.7 million in 2018. This change was primarily driven by the increase in
Income / (loss) from continuing operations before income tax in the current year, partially offset by the decrease in federal tax rate from 35% to 21% and tax benefits associated with the amortization of the impact of the lower income tax rate resulting from the TCJA on our deferred tax balances.
Income tax benefit increased $2.6 million from $2.4 million in 2016 to $5.0 million in 2017. This increase was primarily due to a pre-tax loss in 2017 compared to pre-tax income in 2016 and the one-time re-measurement of deferred tax expense related to the recent enactment of the TCJA.
DPL - Discontinued Operations
During the years ended December
31, 2018, 2017 and 2016, DPL recorded income / (loss) from discontinued operations (net of tax) of $38.9 million, $(93.1) million and $(500.0) million, respectively. This income / (loss) relates to the generation components of Stuart, Killen, Miami Fort, Zimmer, and the Peaker assets, which were disposed of
either by sale or retirement within the last year. See Note 15 – Discontinued
Operations in the Notes to DPL's Consolidated Financial Statements.
RESULTS OF OPERATIONS BY SEGMENT – DPL Inc.
Beginning with the second quarter of 2018, DPL has presented the results of operations of Miami Fort Station, Zimmer Station, the Peaker Assets, Stuart Station and Killen Station as discontinued operations as a group of components for all periods presented. For more information, see Note 15 – Discontinued Operations of Notes to DPL's
Consolidated Financial Statements. AES Ohio Generation now only has operating activity coming from its undivided ownership interest in Conesville, which does not meet the threshold to be a separate reportable operating segment. Because of this, DPL now manages its business through only one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The Utility segment is discussed further below:
Utility
Segment
The Utility segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 525,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are
expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The Utility segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord Facility, which was closed in 2014 and transferred to a third party in the first quarter of 2018, and the Hutchings EGU, which was closed in 2013. These assets did not transfer to AES Ohio Generation as part of DP&L's Generation Separation on October 1, 2017. Thus, they are grouped within the Utility segment for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the Utility segment.
Included
within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s long-term debt and adjustments related to purchase accounting from the Merger. DPL's undivided interest in Conesville is now included within the "Other" column as it no longer meets the requirement for disclosure as a reportable operating segment, since the results of operations of the other generation plants are now presented as discontinued operations. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting
segments.
See Note 13 – Business Segments of Notes to DPL's Consolidated Financial Statements for additional information regarding DPL’s reportable segment.
The following table presents DPL’s Income / (loss) from continuing operations before income tax by business segment:
Years
ended December 31,
$ in millions
2018
2017
2016
Utility
$
104.4
$
88.5
$
143.0
Other
(72.5
)
(95.0
)
(130.6
)
Income
/ (loss) from continuing operations before income tax
$
31.9
$
(6.5
)
$
12.4
Statement
of Operations Highlights - DPL – Utility Segment
The results of operations of the Utility segment for DPL are identical in all material respects and for all periods presented to those of DP&L, which are included in Part II - Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations (Statement of Operations Highlights - DP&L) of this Form 10-K.
Income
from continuing operations before income tax (a)
$
104.4
$
88.5
$
143.6
(a)
For
purposes of discussing operating results, we present and discuss Income from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
DP&L's electric sales and billed customers were as follows:
DP&L retail electric sales represent the total transmission and distribution retail sales for the periods presented. SSO sales were 3,977 KWh, 3,684 KWh and 3,856 KWh for the years ended December 31, 2018, 2017 and 2016, respectively.
(c)
Included within wholesale electric sales is DP&L's
4.9% share of the generation output of OVEC.
During the year ended December 31, 2018, Revenues increased $18.7 million to $738.7 million from $720.0 million in the same period of the prior year. This increase was a result of:
$
in millions
2018 vs. 2017
Retail
Rate
Decrease in energy efficiency and USF revenue rate riders
$
(46.6
)
Decrease
in competitive bid revenue rate rider
(12.5
)
Increase due to implementation of the DMR in November 2017
28.0
Increase due to DRO
9.9
Other
4.7
Net
change in retail rate
(16.5
)
Volume
Increase due to favorable weather, as shown by the 51% increase in cooling degree-days and 15% increase in heating degree-days
31.7
Other
miscellaneous
0.1
Total retail change
15.3
Wholesale
Wholesale
revenues
Increase due to higher wholesale prices and increased volumes for DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at market prices
6.3
RTO revenues and RTO capacity revenues
RTO
revenues and RTO capacity revenues
(2.9
)
Net change in Revenues
$
18.7
During the year ended December
31, 2017, Revenues decreased $88.0 million to $720.0 million from $808.0 million in the same period of the prior year. This decrease was a result of:
$ in millions
2017 vs. 2016
Retail
Rate
Decrease
in energy efficiency and USF revenue rate riders
$
(29.6
)
Decrease in competitive bid revenue rate rider
(22.0
)
Decrease from reverting to ESP 1 rates in September 2016, offset by the implementation of the DMR in November 2017
(22.3
)
Other
4.6
Net
change in retail rate
(69.3
)
Volume
Decrease due to unfavorable weather, as shown by the 27% decrease in cooling degree-days and 5% decrease in heating degree-days
(28.5
)
Other
miscellaneous
0.6
Total retail change
(97.2
)
Wholesale
Wholesale
revenues
Increase due to higher wholesale prices for DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at market prices, and an increase in the load served of other parties through their competitive bid process, partially offset by decreased wholesale volumes for OVEC
During the year ended December 31, 2018, Cost of revenues increased $13.4 million compared to the prior year. This increase was a result of:
$ in millions
2018 vs. 2017
Fuel
Net
fuel costs
$
1.9
Net purchased power
Purchased power
Rate
Decrease
due to lower rates in the competitive bid process
(11.7
)
Volume
Increase due to higher competitive bid purchases due to increased DP&L retail demand
24.6
Total
purchased power change
12.9
RTO charges
(1.6
)
RTO capacity charges
0.2
Net
change in purchased power
11.5
Net change in Cost of Revenues
$
13.4
During the year ended December
31, 2017, Cost of revenues decreased $31.7 million compared to the prior year. This decrease was a result of:
$ in millions
2017 vs. 2016
Fuel
Net fuel costs
Decrease
due to fuel costs deferred in 2015, being collected in 2016
$
(4.8
)
Net purchased power
Purchased power
Rate
Decrease
due to lower rates in the competitive bid process
(19.8
)
Volume
Decrease due to fewer competitive bid purchases due to decreased DP&L retail demand
(7.9
)
Total
purchased power change
(27.7
)
RTO charges
Decrease due to lower transmission and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within DP&L's network, which are incurred and charged to customers in the transmission rider
(1.4
)
RTO
capacity charges
2.2
Net change in purchased power
(26.9
)
Net change in Cost of Revenues
$
(31.7
)
DP&L
- Operation and Maintenance
During the year ended December 31, 2018, Operation and Maintenance expense decreased $16.8 million compared to the prior year. This decrease was a result of:
$ in millions
2018 vs. 2017
Decrease in alternative energy and energy efficiency
programs (a)
$
(34.2
)
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
(8.5
)
Decrease due to higher severance expense in the prior year mostly due to AES restructuring activities
(2.6
)
Increase
in amortization of previously deferred regulatory costs, including rate case costs, certain transmission costs, and various costs collected under the regulatory compliance rider (a)
10.8
Increase in legal and other consulting costs, including write-off of previously deferred rate case costs no longer deemed probable for recovery
8.1
Increase in insurance and claims costs
4.0
Increase
in maintenance of overhead transmission and distribution lines
2.6
Other, net
3.0
Net change in Operations and Maintenance expense
$
(16.8
)
(a)
There
is corresponding revenue associated with these program costs resulting in minimal impact to Net income.
During the year ended December 31, 2017, Operation and Maintenance expense decreased $21.9 million compared to the prior year. This decrease was a result of:
$
in millions
2017 vs. 2016
Decrease in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a)
$
(24.0
)
Decrease in alternative energy and energy efficiency programs (a)
(6.6
)
Increase
in legal and other consulting costs
4.5
Increase in group insurance expense associated with participation in the AES self-insurance plan
4.0
Other, net
0.2
Net
change in Operation and Maintenance expense
$
(21.9
)
(a)
There is corresponding revenue associated with this program resulting in minimal impact to Net income.
DP&L – Depreciation and Amortization
During the year ended December
31, 2018, Depreciation and amortization expense decreased $0.8 million compared to the prior year.
During the year ended December 31, 2017, Depreciation and amortization expense increased $4.3 million compared to the prior year. This change was primarily due to additional investments in transmission and distribution fixed assets.
DP&L – General Taxes
During the year ended December 31, 2018, General taxes decreased
$3.2 million compared to the prior year. The decrease was primarily the result of a favorable adjustment for 2017 Ohio property taxes to reflect actual payments made in 2018.
During the year ended December 31, 2017, General taxes increased $8.3 million. The increase was primarily the result of an increase of $3.8 million in Ohio property tax expense driven by higher tax rates and higher property values, against lower expense in 2016 due to a $2.4 million favorable true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016, a 2017 unfavorable true-up of $1.1 million for the 2016 Ohio property tax accrual to reflect actual payments made in 2017 and a $1.0 million increase in other general taxes.
DP&L
– Loss on Disposal of Business
During the year ended December 31, 2018, DP&L recorded a Loss on disposal of business of $12.4 million due to the loss on the transfer of business interests in the Beckjord facility.
DP&L – Interest Expense
During the year ended December 31, 2018, interest expense decreased $3.2 million compared to the prior year. The decrease was primarily the result of debt repayments at DP&L in 2017 and 2018.
During
the year ended December 31, 2017, interest expense increased $5.8 million compared to the prior year primarily due to higher interest rates. On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds Due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%.
DP&L – Charge for Early Redemption of Debt
During the year ended December
31, 2018, DP&L recorded a charge for early redemption of debt of $0.6 million.
During the year ended December 31, 2017, DP&L recorded a charge for early redemption of debt of
$1.1 million primarily due to the early redemption of the 4.8% Tax-exempt First Mortgage Bonds due 2036.
During the year ended December 31, 2016, DP&L recorded a charge for early redemption
of debt of
$0.5 million.
DP&L – Income Tax Expense
During the year ended December 31, 2018, Income tax expense decreased $13.4 million from $31.1 million in 2017 to $17.7 million in 2018 primarily due to the decrease in the federal corporate income tax rate to 21% from 35% as a result of the passage of the TCJA and the amortization of excess deferred taxes resulting from the TCJA, partially offset by higher pre-tax income in the current year versus the prior year.
During the year ended December 31, 2017, Income tax expense decreased $14.9 million from $46.0 million in 2016 to $31.1 million in 2017 primarily due to a decrease in pre-tax income in the current year, a decrease in the depreciation of AFUDC Equity, and a tax reserve that was recorded in the prior year. Partially offsetting the decrease was a prior year deferred tax adjustment that was not required in the current year.
DP&L - Discontinued Operations
During the years ended December 31, 2017 and 2016,
DP&L recorded losses from discontinued operations (net of tax) of $40.4 million and $870.3 million, respectively. These losses relate to the discontinued DP&L Generation segment, which was transferred to AES Ohio Generation through Generation Separation on October 1, 2017. See Note 14 – Generation Separation in Notes to DP&L's Financial Statements.
KEY TRENDS AND UNCERTAINTIES
Following
the issuance of the DRO in September 2018 and the resulting changes to the decoupling rider effective January 1, 2019, we expect that our financial results will no longer be driven by retail demand and weather but will be impacted by customer growth within our service territory. See further discussion on these changes in Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements. In addition, DPL's and DP&L's financial results are likely to be driven by other
factors including, but not limited to:
•
regulatory outcomes;
•
the passage of new legislation, implementation of regulations or other changes in regulations;
•
timely recovery of transmission and distribution expenditures; and
•
exiting
generation assets currently owned by AES Ohio Generation.
Operational
As part of our announced plan to exit our generation businesses, on May 31, 2018, we retired the Stuart and Killen EGUs. In addition, we closed on a sale of our Peaker assets in March 2018. See Note 15 - Discontinued Operations in the Notes to DPL's Consolidated Financial Statements for additional information. In October 2018, AEP, the operator of the co-owned Conesville EGU, announced that Unit 4 would close by May 2020. For additional information on these events and DPL's coal fired facilities, see Note 15 – Discontinued Operations of Notes
to DPL's Consolidated Financial Statements.
Macroeconomic and Political
United States Tax Law Reform
In December 2017, the U.S. federal government enacted the TCJA. The legislation significantly revised the U.S. corporate income tax system by, among other things, lowering corporate income tax rates and introducing new limitations on interest expense deductions beginning in 2018. These changes will materially impact our effective tax rate in future periods. Specific provisions of the TCJA and their potential impacts on us are noted below. Our interpretation of the TCJA may change as the U.S. Treasury Department and the Internal Revenue
Service issue additional guidance. Such changes may be material.
Lower Tax Rate - The corporate tax rate decreased from 35 percent to 21 percent beginning in 2018. In addition to deferred tax remeasurement impacts, the lower tax rate resulted in the recognition, at December 31, 2017, of a regulatory liability at DP&L. The regulatory liability reflects deferred taxes that will flow back to ratepayers over time. For further details, see “Deferred income taxes payable through rates” of Note 3 – Regulatory Matters and Note 8 – Income Taxes of Notes to DPL's
Consolidated Financial Statements and "Deferred income taxes payable through rates” of Note 3 – Regulatory Matters and Note 8 – Income Taxes of Notes to DP&L's Financial Statements.
SAB 118 - As further explained in Note 8 – Income Taxes of Notes to DPL's Consolidated Financial Statements and Note 8 – Income Taxes of Notes to DP&L's Financial Statements,
we have concluded our analysis of the implementation impacts of the TCJA and included adjustments to our previous estimates in accordance with the guidance of SAB 118.
Limitation on Interest Expense Deductions - The TCJA introduced a new limitation on the deductibility of net interest expense beginning January 1, 2018. The deduction is limited to interest income, plus 30 percent of tax basis EBITDA through 2021 (30 percent of EBIT beginning January 1, 2022). This determination is made at the
consolidated
group level. The limitation does not apply to interest expense attributable to regulated utility property. The U.S. Treasury Department and Internal Revenue Service have released proposed regulations to clarify how the exception will apply to regulated utility holding companies. These proposed regulations are prospective; we have not adopted them for 2018.
Cost Recovery - The TCJA amended depreciation rules to provide full expensing (100% bonus depreciation) for assets that commence construction and are placed in service before January 1, 2023. This provision is phased down by 20 percent ratably through 2027. The immediate full expensing provision is elective, but it does not apply to regulated utility property. This change is not expected to impact our effective tax rate; however, if elected, it could impact
taxable income and cash taxes in future periods.
State Taxes - The reactions of the individual states to federal tax reform is still evolving. These state and municipalities will assess whether and how the federal changes will be incorporated into their tax legislation.
On January 10, 2018 the PUCO initiated a proceeding to consider the impacts of the TCJA to determine the appropriate course of action to pass benefits resulting from the legislation on to ratepayers. The PUCO also directed Ohio utilities to record deferred liabilities for the estimated reduction in federal income tax resulting from the TCJA beginning January 1, 2018. Under the terms of the ESP, DPL will
not make tax sharing payments and if our rates are reduced as a result of the TCJA, DPL's cash flows could be adversely affected. See Note 8 – Income Taxes of Notes to DPL's Consolidated Financial Statements and Note 8 – Income Taxes of Notes to DP&L's Financial Statements for more information.
LIBOR Phase Out
In
July 2017, the U.K. Financial Conduct Authority announced the phase out of LIBOR by the end of 2021. The Alternative Reference Rate Committee within the Federal Reserve is responsible for the transition from LIBOR to a new benchmark replacement rate. While we maintain financial instruments that use LIBOR as an interest rate benchmark, the full impact of the phase out is uncertain until a new replacement benchmark is determined and
implementation plans are more fully developed.
Regulatory Environment
For a comprehensive discussion of the market structure and regulation of DPL and DP&L, see Part I, Item 1 - Business – Competition and Regulation.
In
December 2018, DP&L filed a Distribution Modernization Plan (“DMP”) with the PUCO proposing to invest $576.0 million in capital projects over the next 10 years. There are eight principal components of DP&L’s DMP: 1) Smart Meters, 2) Self-Healing Grid, 3) Customer Engagement, 4) Enhancing Sustainability and Embracing Innovation. 5) Telecommunications, 6) Physical and Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D.
On January 22, 2019, DP&L filed a request with the PUCO for a two-year extension of its DMR through October 2022, in the proposed amount of $199.0 million for each of the two additional years. The request was made pursuant to the PUCO’s
October 20, 2017 ESP order, which approved the DMR and had the option for DP&L to file for a two-year extension. The extension request was set at a level expected to reduce debt obligations at both DP&L and DPL and to position DP&L to make capital expenditures to maintain and modernize its electric grid. To that end, DP&L’s DMP investments are contingent upon the PUCO approving the two-year extension of its DMR.
For more information regarding DP&L's ESP, see Note 3 – Regulatory Matters of Notes
to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements.
CAPITAL RESOURCES AND LIQUIDITY
Cash, cash equivalents and restricted cash for DPL and DP&L was $111.7 million and $66.2 million, respectively, at December
31, 2018. At that date, neither DPL nor DP&L had short-term investments. DPL and DP&L had aggregate principal amounts of debt outstanding of $1,488.4 million and $593.8 million, respectively, at December 31, 2018.
Approximately $103.6 million of DPL's debt and $4.6 million of DP&L's debt matures
within the next twelve months, which we expect to repay using a combination of cash on hand, net cash provided by operating activities and/or net proceeds from the issuance of new debt. From time to time, we may elect to repurchase our outstanding debt
through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.
We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty could have material adverse effects on our financial condition and results of operations. In addition, changes in the timing
of tariff increases or delays in the regulatory determinations could affect the cash flows and results of operations of our business.
DP&L must first seek approval from the PUCO to issue new stocks, bonds, notes, and other evidences of indebtedness. Annually, DP&L must receive authority to issue and assume liability on short-term debt, not to exceed 12 months, pursuant to Section 4905.401 of the Ohio Revised Code. DP&L received an order from the PUCO granting authority through December 31, 2019 to, among other things, issue up to $300.0 million in aggregate principal amount of short-term indebtedness. DP&L must also receive authority to issue and assume liability
on long-term debt, in excess of 12 months, pursuant to Section 4905.40 of the Ohio Revised Code. DP&L last received approval in 2016 to, among other things, issue up to $455.0 million in aggregate principal amount of long-term indebtedness for a term not to exceed 30 years at an interest rate not to exceed 6.60%. DP&L also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under existing debt obligations. DP&L does not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations. In 2019, DP&L filed for approval to, among other things, issue up to $425.0 million in aggregate principal amount of long-term indebtedness
for a term not to exceed 40 years at an interest rate not to exceed 5.75%.
CASH FLOWS
DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation.
Cash Flow Analysis - DPL:
DPL
Years
ended December 31,
$ in millions
2018
2017
2016
Net cash provided by operating activities
$
205.9
$
131.7
$
267.1
Net
cash provided by / (used in) investing activities
129.9
(39.3
)
(141.5
)
Net cash used in financing activities
(250.5
)
(149.6
)
(167.1
)
Increase
in cash and restricted cash of discontinued operations and held-for-sale businesses
1.5
27.5
15.8
Net
increase / (decrease) in cash, cash equivalents and restricted cash
86.8
(29.7
)
(25.7
)
Balance at beginning of year
24.9
54.6
80.3
Cash,
cash equivalents and restricted cash at end of year
The net change in operating assets and liabilities for the year ended December 31, 2018 compared to the year ended December 31, 2017 was driven by the following:
$ in millions
$
change
Increase from accrued taxes payable is primarily due to a prior year income tax benefit and current year income tax expense
$
41.1
Increase from accounts receivable is primarily due to 2018 collections of PJM transmission enhancement settlement and remaining amounts due from partners in jointly-owned stations
27.6
Increase
from accounts payable is primarily due to timing of payments and lower coal purchases in 2018
20.0
Increase from deferred regulatory costs, net, is primarily due to higher collections on regulatory assets and liabilities
14.5
Decrease from pension, retiree and other benefits relates to higher contributions and lower accruals of net periodic benefit costs in 2018
(8.1
)
Increase
from inventory primarily due to lower coal purchases in 2018
7.1
Other
8.1
Net change in cash from changes in operating assets and liabilities
$
110.3
Fiscal
year 2017 versus 2016:
The net change in operating assets and liabilities for the year ended December 31, 2017 compared to the year ended December 31, 2016 was driven by the following:
$ in millions
$ change
Decrease
from accounts payable primarily due to timing of payments and spending patterns
$
(51.4
)
Decrease from accrued taxes payable primarily due to incurring current income tax expense in 2016 compared to a current tax benefit in 2017
(48.8
)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities
(27.8
)
Decrease
from inventory primarily due to lower coal purchases in 2016
(24.3
)
Other
(1.3
)
Net change in cash from changes in operating assets and liabilities
$
(153.6
)
DPL
– Net cash from investing activities
During the year ended December 31, 2018, net cash provided by investing activities primarily relates to proceeds from the sale of business of $234.9 million, primarily due to the sale of the Peaker assets, and proceeds of $10.6 million, related to the June transmission swap with Duke and AEP, partially offset by capital expenditures of $103.6 million and payment on the disposal of Beckjord of $14.5 million.
During the year ended December 31, 2017, net cash used in investing activities primarily relates to capital expenditures
of $121.5 million, partially offset by insurance proceeds of $12.3 million, and $70.1 million of proceeds from the sale of the Miami Fort and Zimmer stations.
During the year ended December 31, 2016, net cash used in investing activities primarily relates to capital expenditures of $148.5 million, partially offset by $6.3 million of insurance proceeds.
DPL – Net cash from financing activities
During the year ended December 31, 2018, net cash used in financing activities
primarily relates to the retirement of $240.5 million of long-term debt, and $10.0 million of net repayments on the revolving credit facilities during the year.
During the year ended December 31, 2017, net cash used in financing activities primarily relates to the retirement of $159.5 million of long-term debt, and $10.0 million of net borrowings on the revolving credit facilities during the year.
During the year ended December 31, 2016, net cash used in financing activities primarily relates to the retirement
of $577.8 million of long-term debt, and the redemption of $23.5 million of preferred stock, partially offset by the issuance of new long-term debt of $442.8 million.
Increase
in cash and restricted cash of discontinued operations and held-for-sale businesses
—
27.0
15.8
Net
increase / (decrease) in cash, cash equivalents and restricted cash
60.6
4.0
(3.8
)
Balance at beginning of year
5.6
1.6
5.4
Cash,
cash equivalents, and restricted cash at end of year
$
66.2
$
5.6
$
1.6
DP&L
– Net cash from operating activities
For the years ended December 31,
$ change
$
in millions
2018
2017
2016
2018 vs. 2017
2017 vs. 2016
Net income / (loss)
$
86.7
$
17.0
$
(772.7
)
$
69.7
$
789.7
Depreciation
and amortization
77.6
88.3
123.2
(10.7
)
(34.9
)
Impairment
expenses
—
66.3
1,353.5
(66.3
)
(1,287.2
)
Other
adjustments to Net income / (loss)
29.5
23.9
(481.3
)
5.6
505.2
Net
income / (loss), adjusted for non-cash items
193.8
195.5
222.7
(1.7
)
(27.2
)
Net
change in operating assets and liabilities
2.0
(60.1
)
14.5
62.1
(74.6
)
Net
cash provided by operating activities
$
195.8
$
135.4
$
237.2
$
60.4
$
(101.8
)
Fiscal
year 2018 versus 2017:
The net change in operating assets and liabilities for the year ended December 31, 2018 compared to the year ended December 31, 2017 was driven by the following:
$ in millions
$ change
Increase
from accounts payable is primarily due to timing of payments and less generation related payments, mostly related to coal purchases
$
52.5
Increase from deferred regulatory costs, net, due to higher collections on regulatory assets and liabilities
14.5
Decrease from inventory primarily due to no longer having coal purchases in 2018
(10.6
)
Other
5.7
Net
change in cash from changes in operating assets and liabilities
$
62.1
Fiscal year 2017 versus 2016:
The net change in operating assets and liabilities for the year ended December 31, 2017 compared to the year ended December 31, 2016 was driven by the following:
$
in millions
$ change
Decrease from accounts payable primarily due to timing of payments and spending patterns
$
(63.3
)
Decrease from deferred regulatory costs, net, due to lower collections on regulatory assets and liabilities
(27.8
)
Increase
from accounts receivable primarily due to timing of collections
22.9
Other
(6.4
)
Net change in cash from changes in operating assets and liabilities
$
(74.6
)
DP&L
– Net cash from investing activities
During the year ended December 31, 2018, net cash used in investing activities primarily relates to capital expenditures of $93.1 million and payment on the disposal of Beckjord of $14.5 million, partially offset by proceeds of $10.6 million related to the June transmission asset swap with Duke and AEP.
During the year ended December 31, 2017, net cash used in investing activities primarily relates to capital expenditures of $101.7 million, partially offset by insurance proceeds
of $12.5 million.
During the year ended December 31, 2016, net cash used in investing activities primarily relates to capital expenditures of $128.3 million, partially offset by insurance proceeds of $6.1 million.
During
the year ended December 31, 2018, net cash used in financing activities primarily relates to the retirement of $64.5 million of long-term debt, returns of capital paid to parent of $43.8 million, and $10.0 million net repayments on revolving credit facilities during the year, partially offset by a $80.0 million capital contribution from DPL.
During the year ended December 31, 2017, net cash used in financing activities primarily relates to retirement of $104.5 million of long-term debt and dividends and return of capital paid to parent of $39.0 million, partially offset by a $70.0
million capital contribution from DPL.
During the year ended December 31, 2016, net cash used in financing activities primarily relates to the retirement of $445.3 million of long-term debt, $70.0 million in dividends paid on common stock to parent, related party repayments, net of related party borrowings, of $30.0 million, and redemption of $23.5 million of preferred stock, partially offset by the issuance of $442.8 million of new long-term debt.
Liquidity
We expect our existing sources of liquidity to remain sufficient to meet our anticipated operating needs.
Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to energy hedges, taxes and dividend payments. For 2019 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods. In addition, DP&L's 2017 ESP provides for a DMR, which will be used for debt obligations at DPL and DP&L. See Note 3 – Regulatory Matters
for more information.
At December 31, 2018, DPL and DP&L have access to the following revolving credit facilities:
DP&L's
revolving credit facility has a commitment of $175.0 million, with a $50.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and extending the term of the facility from May 2018 to July 2020. At December 31, 2018, DP&L had nothing drawn under this facility and had one letter of credit in the amount of $1.1 million outstanding, with the remaining $173.9 million available to DP&L. Fees associated with this facility were not material during the years ended December 31, 2018,
2017 or 2016.
DPL has a revolving credit facility of $205.0 million, with a $200.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $95.0 million. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells
Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by AES Ohio Generation secured by assets of AES Ohio Generation. DPL further secured the credit facility through a leasehold mortgage on additional assets of AES Ohio Generation. The facility expires in July 2020; however, DPL's credit facility has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. At December 31, 2018,
there were five letters of credit in the aggregate amount of $14.0 million outstanding under this facility, and nothing borrowed on the facility, with the remaining $191.0 million available to DPL. Fees associated with this facility were not material during the years ended December 31, 2018, 2017 or 2016.
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 laws, rules and regulations, among other factors.
DPL is projecting to spend an estimated $628.0 million in capital projects for the period 2019 through 2021, which includes expected spending under DP&L's Distribution Modernization Plan ("DMP") filed with the PUCO in December 2018. DP&L's 2017 ESP also provided for a DMR to pay debt obligations at DPL and DP&L
and position DP&L to modernize and/or maintain its transmission and distribution infrastructure. See Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements for more information. On January 22, 2019, DP&L filed a request with the PUCO for a two-year extension of its DMR through October 2022, in the proposed amount of $199.0 million for each of the two additional years. The request was made pursuant to the PUCO’s October
20, 2017 ESP order, which approved the DMR and had the option for DP&L to file for a two-year extension. The extension request was set at a level expected to reduce debt obligations at both DP&L and DPL and to position DP&L to make capital expenditures to maintain and modernize its electric grid. To that end, DP&L’s DMP investments are contingent upon the PUCO approving the two-year extension of its DMR.
DP&L is subject to the mandatory reliability standards of NERC and Reliability First Corporation (RFC), one of the eight NERC regions, of which DP&L is a member.
NERC has recently changed the definition of the Bulk Electric System to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply. DP&L’s 138 kV facilities were previously not subject to these reliability standards. Accordingly, DP&L anticipates spending approximately $221.0 million within the next five years to reinforce its 138-kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.
Debt
Covenants
For information regarding our long-term debt covenants, see Note 7 – Long-term debt of Notes to DPL's Consolidated Financial Statements and Note 7 – Long-term debt of Notes to DP&L's Financial Statements.
Debt Ratings
The following table outlines the debt ratings and outlook for DPL and DP&L, along with the effective or affirmed date of each rating.
DPL
DP&L
Outlook
Effective
or Affirmed
Fitch Ratings
BBB(a) / BBB-(b)
A- (c)
Stable
October 2018
Moody's Investors Service, Inc.
Ba1 (b)
A3 (c)
Positive
October
2018
Standard & Poor's Financial Services LLC
BBB- (b)
BBB+ (c)
Stable
March 2018
(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.
Credit Ratings
The following table outlines the credit ratings (issuer/corporate
rating) and outlook for each company, along with the effective or affirmed dates of each rating and outlook for DPL and DP&L.
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 certain contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities. Non-investment grade companies may experience higher costs to issue new securities.
Off-Balance Sheet Arrangements
DPL – Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned
subsidiary, AES Ohio Generation, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish this subsidiary's intended commercial purposes. During the year ended December 31, 2018, DPL did not incur any losses related to the guarantees of these obligations and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.
At December
31, 2018, DPL had $23.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of AES Ohio Generation to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. We had no outstanding balance of obligations for commercial transactions covered by these guarantees at December 31, 2018. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.9 million
at December 31, 2017.
DP&L owns a 4.9% equity ownership interest in OVEC which is recorded using the cost method of accounting under GAAP. At December 31, 2018, DP&L could be responsible for the repayment of 4.9%, or $68.1 million, of a $1,389.6 million debt obligation comprised of both fixed and variable rate securities with maturities between 2019 and 2040. This would only happen if this
electric generation company defaulted on its debt payments. At December 31, 2018, we have no knowledge of such a default.
Commercial Commitments and Contractual Obligations
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2018, these include:
Payments
due in:
$ in millions
Total
Less than 1 year
2 - 3 years
4 - 5 years
More than 5 years
DPL:
Long-term
debt
$
1,488.4
$
103.6
$
929.4
$
423.0
$
32.4
Interest
payments
274.4
86.6
145.3
15.9
26.6
Pension
and postretirement payments
264.6
27.8
54.7
53.6
128.5
Electricity
purchase commitments
209.4
139.5
69.9
—
—
Purchase
orders and other contractual obligations
40.2
11.4
14.8
14.0
—
Total
contractual obligations
$
2,277.0
$
368.9
$
1,214.1
$
506.5
$
187.5
Payments
due in:
$ in millions
Total
Less than 1 year
2 - 3 years
4 - 5 years
More than 5 years
DP&L:
Long-term
debt
$
593.8
$
4.6
$
149.4
$
423.0
$
16.8
Interest
payments
94.5
23.7
41.0
13.4
16.4
Pension
and postretirement payments
264.6
27.8
54.7
53.6
128.5
Electricity
purchase commitments
209.4
139.5
69.9
—
—
Purchase
orders and other contractual obligations
39.8
11.3
14.7
13.8
—
Total
contractual obligations
$
1,202.1
$
206.9
$
329.7
$
503.8
$
161.7
Long-term
debt:
DPL’s Long-term debt at December 31, 2018 consists of DPL’s unsecured notes, secured term loan and Capital Trust II securities, along with DP&L’s First Mortgage Bonds, tax-exempt First Mortgage Bonds and the Wright-
Patterson Air Force Base (WPAFB) note. These long-term debt amounts include current maturities but exclude unamortized debt discounts, premiums and fair value adjustments.
DP&L’s
Long-term debt at December 31, 2018 consists of its First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. These long-term debt amounts include current maturities but exclude unamortized debt discounts.
See Note 7 – Long-term debt of the Notes to DPL's Consolidated Financial Statements and Note 7 – Long-term debt of the Notes to DP&L's Financial Statements.
Interest payments:
Interest
payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rates in effect at December 31, 2018.
Pension and postretirement payments:
At December 31, 2018, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 9 – Benefit Plans of Notes to DPL's Consolidated Financial Statements
and Note 9 – Benefit Plans of Notes to DP&L's Financial Statements. These estimated future benefit payments are projected through 2028. This amount also includes postretirement benefit costs.
Electricity purchase commitments:
DPL enters into long-term contracts for the purchase of electricity. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.
Purchase orders and other contractual obligations:
At December
31, 2018, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and DPL's and DP&L's ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. See Note 12 – Related Party Transactions of Notes to DPL's Consolidated Financial Statements and Note 12 – Related Party Transactions
of Notes to DP&L's Financial Statements for additional information on charges between related parties and amounts due to or from related parties.
Reserve for uncertain tax positions:
Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $3.5 million at December 31, 2018, we are unable to make a reliable estimate of the periods of cash settlement with the respective tax authorities and have not included such amounts in the contractual obligations table above.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
DPL’s Consolidated Financial Statements and DP&L’s Financial Statements are prepared in accordance with GAAP. In connection with the preparation of these financial statements, our management is required to make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and the related disclosure of contingent liabilities. These assumptions, estimates and judgments are based on our historical experience and assumptions that we believe to be reasonable at the time. However, because future events and their effects cannot be determined with certainty, the determination of estimates requires the exercise of judgment. Our critical accounting estimates are those which require assumptions to be made about matters that are highly
uncertain. Our significant accounting policies are described in Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DPL's Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L's Financial Statements.
Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed
materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of allowances for deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery
services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Income Taxes
We are subject to federal and state income taxes. Our income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the U.S. Internal Revenue Service and other tax authorities. We regularly assess the potential outcome of tax examinations when determining the adequacy of our income tax provisions by considering the technical merits of the filing position, case law, and results of previous tax examinations. Accounting
guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold and measurement requirements for financial statement reporting of our income tax positions. Tax reserves have been established which we believe to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While we believe that the amount of the tax reserves is reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.
Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases.
We establish a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.
Regulatory Assets and Liabilities
Application of the provisions of GAAP relating to regulatory accounting requires us to reflect the effect of rate regulation in DPL’s Consolidated Financial Statements and DP&L’s Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by non-regulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as Regulatory
assets that otherwise would be expensed by non-regulated companies. Likewise, we recognize Regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenses that are not yet incurred. Regulatory assets are amortized into expense and Regulatory liabilities are amortized into income over the recovery period authorized by the regulator.
We evaluate our Regulatory assets to determine whether or not they are probable of recovery through future rates and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be expensed in the period
the assessment is made. We currently believe the recovery of our Regulatory assets is probable. See Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements.
AROs
In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized
as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time. See Note 4 – Property, Plant and Equipment of Notes to DPL's Consolidated Financial Statements and Note 4 – Property, Plant and Equipment
of Notes to DP&L's Financial Statements for more information.
In accordance with the provisions of GAAP relating to the accounting for impairments, long-lived assets are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used are recognized based on the fair value of the asset group. Impairment losses on assets held-for-sale are recognized
based on the fair value of the disposal group. We determine the fair value of these assets based upon estimates of future cash flows, market value of similar assets, if available, or independent appraisals, if required. In analyzing the fair value and recoverability using future cash flows, we make projections based on a number of assumptions and estimates of growth rates, future economic conditions, assignment of discount rates and estimates of terminal values. An impairment loss is recognized if the carrying amount of the long-lived asset is not recoverable from its undiscounted cash flows. The measurement of impairment loss is the difference between the carrying amount and fair value of the asset.
Pension and Postretirement Benefits
We account for and disclose pension and postemployment benefits in accordance with the provisions of
GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans. See Note 9 – Benefit Plans of Notes to DPL's Consolidated Financial Statements and Note 9 – Benefit Plans of Notes to DP&L's Financial Statements for more information.
Contingent and Other Obligations
During the conduct of our business, we are subject to a number of federal
and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We believe such estimates and assumptions are reasonable.
Recently Issued Accounting Pronouncements
A discussion of recently issued accounting pronouncements is in Note
1 – Overview and Summary of Significant Accounting Policies of Notes to DPL's Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L's Financial Statements and such discussion is incorporated by reference in this Management's Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.
LEGAL AND OTHER MATTERS
Discussions
of legal and other matters are provided in Item 1 – Business "Environmental Matters", Item 1 – Business "Competition and Regulation" and Item 3 – Legal Proceedings. Such discussions are incorporated by reference in this Management's Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.
Item 7A – Quantitative and Qualitative Disclosures about Market Risk
We
are subject to certain market risks including, but not limited to, changes in commodity prices for electricity and fluctuations in interest rates. We use various market risk-sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in interest rates. Our U.S. Risk Management Committee (U.S. RMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures related to our operations. The U.S. RMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.
The disclosures presented in this section are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of
1934 shall apply to the disclosures contained in this section. For further information regarding market risk, see Item 1A.-Risk Factors. Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the electricity markets, which could have a material adverse effect on our financial performance; and we may not be adequately hedged against our exposure to changes in interest rates.
Purchased power costs
DP&L
conducts competitive bid auctions to purchase power for SSO service, as all of DP&L's SSO is sourced through the competitive bid auction.
As a result of DPL's exit from the majority of its coal-fired generation, changes in the prices of fuel and purchased power are not expected to have a material impact on our results of operations, financial position or cash flows.
Interest rate risk
Because of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates, which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected
by adverse interest rate fluctuations. DPL and DP&L have both fixed-rate and variable rate long-term debt. On November 21, 2016, the DP&L $200.0 million variable-rate First Mortgage Bonds were hedged with floating for fixed interest rate swaps, reducing interest rate risk exposure for the term of the bonds. On January 1, 2018 the interest rate on these First Mortgage Bonds was adjusted and as a result the bonds are no longer fully hedged and are treated as variable. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 7 – Long-term debt of Notes to DPL's
Consolidated Financial Statements and Note 7 – Long-term debt of Notes to DP&L's Financial Statements. At December 31, 2018, a 1% change in interest rates would result in an approximately $14.9 million change in DPL's interest expense and an approximately $5.9 million change in DP&L's interest expense.
Principal payments and interest rate detail by contractual maturity date
The principal amount
of DPL’s long-term debt was $1,488.4 million at December 31, 2018, consisting of DPL’s unsecured notes, secured term loan, Capital Trust II securities along with DP&L’s First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. All of DPL’s existing debt was adjusted to fair value at the Merger date according to FASB Accounting Standards Codification No. 805, “Business Combinations”. The fair value of this debt at December 31, 2018 was $1,519.6 million, based on current market prices
or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:
The principal amount of DP&L’s long-term debt was $593.8 million at December 31, 2018, consisting of its First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. The fair value of this debt at December 31, 2018 was $593.8 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DP&L’s debt obligations that are sensitive to interest rate changes. The DP&L
debt was not revalued using push-down accounting as a result of the Merger.
DP&L
Years
ending December 31,
Principal amount at December 31,
Fair value at December 31,
$ in millions
2019
2020
2021
2022
2023
Thereafter
2018
2018
Long-term
debt (a)
Variable-rate
debt
$
4.5
$
144.5
$
4.5
$
422.6
$
—
$
—
$
576.1
$
576.1
Average
interest rate
4.4
%
3.0
%
4.4
%
4.4
%
—
%
—
%
Fixed-rate
debt
$
0.1
$
0.2
$
0.2
$
0.2
$
0.2
$
16.8
17.7
17.7
Average
interest rate
4.2
%
4.2
%
4.2
%
4.2
%
4.2
%
4.2
%
Total
$
593.8
$
593.8
Equity
price risk
At December 31, 2018, approximately 33% of the defined benefit pension plan assets were comprised of investments in equity securities and 67% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. The equity securities are carried at their market value of approximately $105.2 million at December 31, 2018. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10.5 million reduction in fair value at December
31, 2018 and approximately a $1.6 million increase to the 2019 pension expense.
Credit risk
Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We limit our credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been originated. We use the three leading corporate credit rating agencies and other current market-based qualitative and quantitative
data to assess the financial strength of counterparties on an ongoing basis. We may require various forms of credit assurance from counterparties to mitigate credit risk.
Item 8 – Financial Statements and Supplementary Data
This report includes the combined filing of DPL and DP&L. Throughout this report, the terms “we,”“us,”“our” and “ours” are used to refer to both DPL and DP&L,
respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of DPL Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of DPL Inc. (the Company) as of December 31, 2018 and 2017,
the related consolidated statements of operations, comprehensive income / (loss), cash flows and shareholder’s equity for each of the three years in the period ended December 31, 2018, and the related notes and schedule (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These
financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing
procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Consolidated Statements of Comprehensive Income / (Loss)
Years ended December 31,
$ in millions
2018
2017
2016
Net
income / (loss)
$
70.1
$
(94.6
)
$
(485.2
)
Equity securities activity:
Change
in fair value of equity securities, net of income tax expense of $0.0, ($0.2) and ($0.1) for each respective period
—
0.5
0.2
Reclassification to earnings, net of income tax expense of $0.0 for each respective period
—
(0.1
)
—
Net
change in fair value of equity securities
—
0.4
0.2
Derivative activity:
Change
in derivative fair value, net of income tax benefit / (expense) of $0.1, ($5.3) and ($8.8) for each respective period
(0.1
)
9.6
16.1
Reclassification to earnings, net of income tax benefit of $0.4, $0.3 and $0.5 for each respective period
(0.8
)
(0.7
)
(0.5
)
Reclassification
of earnings related to discontinued operations, net of income tax benefit / (expense) of ($1.2), $4.1 and $16.2 for each respective period
3.2
(7.3
)
(29.2
)
Net change in fair value of derivatives
2.3
1.6
(13.6
)
Pension
and postretirement activity:
Prior service cost for the period, net of income tax benefit of $0.6, $0.4 and $0.0 for each respective period
(2.2
)
(0.7
)
—
Net
gain / (loss) for the period, net of income tax benefit / (expense) of ($0.5), $1.1 and $2.4 for each respective period
1.7
(1.8
)
(4.7
)
Reclassification to earnings, net of income tax expense of ($0.2), ($0.5) and ($0.6) for each respective period
0.6
1.0
1.0
Net
change in unfunded pension and postretirement obligations
Includes $5.1 million charged to Other paid-in capital for the redemption of the DP&L preferred shares. See Note 10 – Equity.
(c)
Represents the conversion of a tax sharing payable to AES to contributed capital, as DP&L's 2017 ESP restricts tax sharing payments to AES during the term of the ESP.
See Note 8 – Income Taxes.
(d)
ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.6 million ($1.0 million net of tax) was reversed to Accumulated deficit.
For the years ended December 31, 2018, 2017 and 2016
Note
1 – Overview and Summary of Significant Accounting Policies
Description of Business
DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL has one reportable segment, the Utility segment. See Note 13 – Business Segments for more information relating to our reportable segment. The terms “we”, “us”, “our” and “ours” are used to refer to DPL and its subsidiaries.
On
November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. Following the merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES.
DP&L, DPL's wholly-owned subsidiary, is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribution services are still regulated. DP&L
has the exclusive right to provide such service to its approximately 525,000 customers located in West Central Ohio. DP&L provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Since January 2016, DP&L has been sourcing all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in multiple coal-fired power stations and multiple peaking
electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L-owned generating facilities, excluding the Beckjord Facility and Hutchings EGU, were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL, through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Also, Stuart Station Unit 1 was retired on October 1, 2017. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's
sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. Through the date of Generation Separation, DP&L sold energy and capacity into the wholesale market.
DPL’s other primary subsidiaries include MVIC and AES Ohio Generation. MVIC is our captive insurance company that provides insurance services to DPL and our subsidiaries. AES Ohio Generation owns an undivided interest in Conesville Unit 4. AES Ohio Generation sells all of its energy and capacity into the wholesale market. DPL's subsidiaries are wholly-owned.
On
December 8, 2017, AES Ohio Generation completed the sale of the Miami Fort and Zimmer stations to subsidiaries of Dynegy in accordance with an asset purchase agreement dated April 21, 2017. In addition, on March 27, 2018, DPL and AES Ohio Generation completed the sale of their Peaker assets to Kimura Power, LLC. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. See Note 15 – Discontinued Operations for additional information.
DPL
also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. 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 or overcollections of riders.
DPL and its subsidiaries employed 659
people at January 31, 2019, of which 647 were employed by DP&L. Approximately 57% of all DPL employees are under a collective bargaining agreement.
Financial Statement Presentation
We prepare Consolidated Financial Statements for DPL. DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP.
AES Ohio Generation's undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, net of subsequent impairments. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations.
Through June 2018, DP&L had undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities were accounted for on a pro rata basis in the Consolidated Financial Statements. In June 2018, DP&L closed on a transmission asset transaction with
Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L, Duke or AEP after the transaction. See Note 4 – Property, Plant and Equipment for more information.
All material intercompany accounts and transactions are eliminated in consolidation. We have evaluated subsequent events through the date this report is issued.
Certain amounts from prior periods have been reclassified to conform to the current period presentation.
The
preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
Revenue Recognition
Revenues
are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our Consolidated Statements of Operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter
reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.
The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred. All of the power produced at the generation station is sold to an RTO. We record expenses when purchased electricity is received and when expenses are incurred. For additional information, see Note 14 – Revenue.
Allowance for Uncollectible
Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.
Property, Plant and Equipment
We record our ownership share of our undivided interest in our jointly-held station as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction
projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $0.5 million, $1.7 million and $2.1 million in the years ended December 31, 2018, 2017 and 2016, respectively.
For
unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction per the provisions of GAAP related to the accounting for capitalized interest.
For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization, consistent with composite depreciation practices.
Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.
Repairs and Maintenance
Costs associated with maintenance activities
are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 4.3% in 2018, 5.0% in 2017 and 6.1%
in 2016 (including property classified in non-current assets of discontinued operations and held-for-sale businesses in 2017 and 2016). Depreciation expense was $66.5 million, $70.4 million and $67.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.
Regulatory Accounting
As a regulated utility, DP&L applies the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking
and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.
The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific
orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 – Regulatory Matters for more information.
Inventories
Inventories
are carried at average cost, net of reserves, and include coal, limestone and materials and supplies used for utility operations.
Intangibles
Intangibles include software, emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired.
Software
is amortized over seven years. Amortization expense was $6.6 million, $5.7 million and $6.6 million for the years ended December 31, 2018, 2017 and 2016, respectively. The estimated amortization expense of this internal-use software over the next five years is $15.0 million ($4.2 million in 2019, $3.2 million in 2020, $3.0 million in 2021, $2.6 million in 2022 and $2.0 million in 2023).
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the
Consolidated Statement of Operations.
Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liability with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 – Regulatory Matters for additional information.
DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated
tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 – Income Taxes for additional information.
Financial Instruments
Our Master Trust investments in debt and equity financial instruments of publicly traded entities are classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on these securities are recorded in Other income. As these financial instruments are held to be used for the benefit of employees participating in employee benefit plans and are not used for general operating purposes, they are classified as non-current in Other deferred assets on the
Consolidated Balance Sheets.
Held-for-sale Businesses
A business classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the business exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long-lived assets until the completion of the sale, at which point, any additional loss is recognized. If the fair value of the business subsequently exceeds the carrying amount while the business is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the previously recognized expense or the subsequent excess.
Assets and liabilities related
to a business classified as held-for-sale are segregated in the current balance sheet in the period in which the business is classified as held-for-sale. Assets and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within twelve months. Transactions between the business held-for-sale and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note 15 – Discontinued Operations for further information.
Discontinued Operations
Discontinued operations reporting occurs only when the disposal of a business or a group of assets represents a strategic shift that has (or will have) a major effect on our operations and financial results.
We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the Consolidated Statements of Cash Flows.
Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued
operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 15 – Discontinued Operations for further information.
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction
in revenues in the accompanying Consolidated Statements of Operations. The amounts for the years ended December 31, 2018, 2017 and 2016, were $51.7 million, $49.4 million and $50.9 million, respectively.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Restricted
Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral and cash collected under the DMR which is restricted to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure.
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Consolidated Balance Sheet that reconcile to the total of such amounts as shown on the Consolidated Statements of
Cash Flows:
Cash, Cash Equivalents, and Restricted Cash, End of Period
$
111.7
$
24.9
Financial
Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
We use interest rate hedges to manage the interest rate risk of our variable rate debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized
for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information.
Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us and our subsidiaries for workers’ compensation, general liability, and property damage on an ongoing basis. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately
$4.1 million and $3.0 million at December 31, 2018 and 2017, respectively. DPL has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of third-party providers of approximately $4.3 million and $4.4 million at December 31, 2018 and 2017, respectively, within Other current liabilities and Other deferred
credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DPL are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates, and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.
Pension and Postretirement Benefits
We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes from actuarial gains or losses related to our regulated operations, that would otherwise be recognized in AOCI, recorded
as a regulatory asset as this can be recovered through future rates. Such changes that are not related to our regulated operations are recognized in AOCI. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the
discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of FASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.
See Note 9 – Benefit Plans for more information.
Related Party Transactions
In the normal course of business, DPL enters into transactions with related parties. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial
Statements.
See Note 12 – Related Party Transactions for more information on Related Party Transactions.
DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as an unconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.2 million
and $0.3 million at December 31, 2018 and 2017, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6 million and $15.6 million at December 31, 2018 and 2017, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 7 – Long-term debt for additional
information.
In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.
The following table provides a brief description of recently adopted accounting pronouncements that had an impact on our consolidated
financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on our consolidated financial statements.
Accounting Standard
Description
Date of Adoption
Effect on the financial statements upon adoption
New Accounting Standards Adopted
2018-15,
Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract
This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. Transition method: retrospective or prospective.
We elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on our financial statements.
2018-14,
Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework
This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Transition method: retrospective.
Impact limited to changes in financial statement disclosures.
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
This standard changes the presentation of non-service costs
associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: retrospective for presentation of non-service cost and prospective for the change in capitalization.
For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Other expense of $2.2 million and $3.2 million, respectively.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)
This
standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.
For the years ended December 31, 2017 and 2016, we reclassified from "Net cash used in investing activities" to "Net increase / (decrease) in cash, cash equivalents and restricted
cash" $27.1 million and ($11.8) million, respectively.
2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments.
Transition method: modified retrospective. Prospective for equity investments without readily determinable fair value.
We
adopted this standard January 1, 2018. At that date, we transferred $1.6 million ($1.0 million net of tax) of unrealized gains from AOCI to Accumulated Deficit.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)
Adoption of FASC Topic 606, "Revenue from Contracts with Customers"
On
January 1, 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers", and its subsequent corresponding updates ("FASC 606"). The core principle of this standard is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We applied the modified retrospective method of adoption to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under FASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified
before January 1, 2018, we have not retrospectively restated the contracts for modifications. We instead reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis.
There was no cumulative effect to our January 1, 2018 Consolidated Balance
Sheet resulting from the adoption of FASC 606.
New accounting pronouncements issued but not yet effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our consolidated financial statements.
Accounting Standard
Description
Date
of Adoption
Effect on the financial statements upon adoption
New Accounting Standards Issued but Not Yet Effective
2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI
This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected.
We do not expect any impact on our consolidated financial statements upon adoption of the standard on January 1, 2019.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities
The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges,
this means that the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.
We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2018-19, 2016-13, Financial Instruments - Credit Losses
(Topic 326): Measurement of Credit Losses on Financial Instruments
The standard updates the impairment model for financial assets measured at amortized cost. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities.
We have adopted the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on our consolidated financial statements.
Adoption of
FASC Topic 842, "Leases"
ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions.
The standard must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which we have elected, that allows entities to continue to apply the guidance in FASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, we will apply the transition provisions starting on January 1, 2019.
We
have elected to apply a package of practical expedients that allow lessees and lessors not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases.
We have also elected to apply an optional transition practical expedient for land easements that allows an entity to continue applying its current accounting policy for all land easements that exist before
the standard’s effective date that were not previously accounted for under FASC 840.
We established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of the real estate-specific guidance and changes to certain lessor
classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize a lease receivable. According to FASC 842, the lease receivable includes the fair value of the plant after the contract period but does not include any variable payments such as margin on the sale of energy. Therefore, the lease receivable could be significantly different than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.
The adoption of FASC 842 did not have a material impact on our consolidated financial statements.
Note
2 – Supplemental Financial Information
December 31,
$ in millions
2018
2017
Accounts
receivable, net
Customer receivables
$
55.8
$
45.2
Unbilled
revenue
16.8
18.0
Due from PJM transmission enhancement settlement (a)
16.5
—
Other
2.3
2.5
Provisions
for uncollectible accounts
(0.9
)
(1.1
)
Total accounts receivable, net
$
90.5
$
64.6
Inventories,
at average cost
Fuel and limestone
$
1.9
$
4.1
Materials
and supplies
8.3
8.1
Other
0.5
0.5
Total
inventories, at average cost
$
10.7
$
12.7
(a) - See Note 3 – Regulatory Matters for more information.
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2018, 2017 and 2016 are as follows:
Details
about Accumulated Other Comprehensive Income / (Loss) Components
Affected line item in the Consolidated Statements of Operations
Years ended December 31,
$ in millions
2018
2017
2016
Gains
and losses on equity securities (Note 5):
Other deductions
$
—
$
(0.1
)
$
—
Income
tax expense
—
—
—
Net of income taxes
—
(0.1
)
—
Gains
and losses on cash flow hedges (Note 6):
Interest expense
(1.2
)
(1.0
)
(1.0
)
Income
tax benefit
0.4
0.3
0.5
Net of income taxes
(0.8
)
(0.7
)
(0.5
)
Gain
/ (loss) from discontinued operations
4.4
(11.4
)
(45.4
)
Tax benefit / (expense) from discontinued operations
(1.2
)
4.1
16.2
Net
of income taxes
3.2
(7.3
)
(29.2
)
Amortization
of defined benefit pension items (Note 9):
Other income
0.8
1.5
1.6
Income
tax expense
(0.2
)
(0.5
)
(0.6
)
Net of income taxes
0.6
1.0
1.0
Total
reclassifications for the period, net of income taxes
$
3.0
$
(7.1
)
$
(28.7
)
The
changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2018 and 2017 are as follows:
ASU
2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.6 million ($1.0 million net of tax) was reversed to Accumulated Deficit.
Note 3 – Regulatory Matters
Distribution
Rate Order
On September 26, 2018 the PUCO issued the DRO establishing new base distribution rates for DP&L, which became effective October 1, 2018. The DRO approved, without modification, a stipulation and recommendation
previously filed by DP&L, along with various intervening parties and the PUCO staff. The DRO established a revenue requirement of $248.0
million for DP&L's electric service base distribution rates which reflects an increase to distribution revenues of approximately $29.8 million per year. In addition to the increase in base distribution rates, and among other matters, the DRO provides for a return on equity of 9.999% and a cost of long-term debt of 4.8% and for the following items:
DIR – The DRO authorized DP&L to begin charging a Distribution Investment Rider ("DIR") set initially at $12.2 million annually, effective October
1, 2018. The DIR revenue requirement shall be updated quarterly and will increase as DP&L makes qualified investments in its distribution network, subject to annual revenue limits which increase each year; the revenue limit for 2019 is $22.0 million. The DIR will expire in November 2022 unless DP&L files a base distribution rate case on or before October 31, 2022, in which case the DIR will expire in November 2023.
Decoupling Rider – The DRO eliminated provisions in the existing decoupling rider which allowed DP&L to recover lost revenues resulting from the implementation of energy efficiency programs and replaced
it with a revenue requirement that attempts to eliminate the impacts of weather and demand on DP&L’s revenues from residential and commercial distribution customers beginning January 1, 2019. As a result, in years with very mild weather and/or decreased demand, DP&L will be able to accrue a regulatory asset for recovery through the rider to normalize the revenues. Conversely, in periods of extreme temperatures or high demand for electricity, DP&L may record a liability for future reimbursement to customers. The rider also includes a one-time $3.7 million revenue requirement based on the increase in the number of DP&L’s residential and commercial customers from the rate case test
year until September 30, 2018. Such amount was accrued and included in revenues in the third quarter of 2018 and will be collected by DP&L in 2019.
TCJA – The DRO partially resolved the TCJA impacts. The new distribution rates include the impacts of the decrease in current federal income taxes beginning October 1, 2018. The DRO did not designate how much DP&L may owe for any overcollection of taxes from January 1, 2018 through September 30, 2018, nor did it resolve any decrease in future rates related to amortization of excess accumulated deferred income taxes
(“ADIT”). The DRO did, however, stipulate that DP&L must refund its customers an amount no less than $4.0 million per year for the first five years of the amortization period unless all balances owed are fully returned within the first five years. For more on the impacts of the TCJA, see below.
Vegetation Management Costs – The DRO authorizes DP&L to defer as a regulatory asset, with no carrying costs, annual expenses for vegetation management performed by third-party vendors. For calendar year 2018 annual expenses which are incremental to the baseline of $10.7 million can be deferred up to a $4.6 million cap. For
calendar years 2019 and thereafter, annual expenses in excess of $15.7 million can be deferred up to a $4.6 million annual cap. Annual spending of less than the vegetation management baseline amounts will result in a reduction to the regulatory asset or creation of a regulatory liability. For 2018, DP&L accrued a regulatory asset for the maximum amount of $4.6 million based upon such provisions and spending above the baseline.
In December 2018, DP&L filed a Distribution Modernization Plan (“DMP”) with the PUCO proposing to invest $576.0 million in capital projects over the next 10 years. There
are eight principal components of DP&L’s DMP: 1) Smart Meters, 2) Self-Healing Grid, 3) Customer Engagement, 4) Enhancing Sustainability and Embracing Innovation. 5) Telecommunications, 6) Physical and Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D.
ESP Order
On March 13, 2017, DP&L filed an amended stipulation to its 2017 ESP, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The six-year 2017 ESP establishes DP&L's framework for providing
retail service on a going-forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms which include, but are not limited to, the following:
•
Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;
•
The establishment of a three-year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 million
in revenue per year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure with an option for DP&L to file for
an extension of the rider for an additional two years in an amount subject to approval by the PUCO. Consistent with that settlement and the PUCO order, on January 22, 2019, DP&L
filed a request to extend the DMR for the additional two years at an annual revenue amount of $199.0 million. That request is pending PUCO review;
•
The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which was established in the DP&L DRO;
•
A non-bypassable Reconciliation Rider permitting DP&L to defer,
recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in OVEC and DP&L's OVEC related costs;
•
Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order. These riders became effective November 1, 2017;
•
A
commitment to commence a sale process to sell our ownership interests in the Miami Fort, Zimmer and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L;
•
Restrictions on DPL making dividend or tax sharing payments and an obligation to convert then existing tax payments owed by DPL to AES into equity investments in DPL. See Note 8 – Income Taxes and Note 10 – Equity for more information on the
tax sharing payment restrictions; and
•
Various other riders and competitive retail market enhancements.
On October 19, 2018 IGS, a retail electricity supplier, filed a Notice of Withdrawal from the amended settlement, citing a material modification by the PUCO's October 2017 order. To address the withdrawal, the PUCO established a new procedural schedule, including a hearing currently scheduled to begin April 1, 2019. Additionally, on January 7,
2019, the Ohio Consumers' Counsel appealed the 2017 ESP Order to the Supreme Court of Ohio. That appeal is pending.
DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The 2017 ESP maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded from the SEET calculation. On October 22, 2018, a stipulation was reached agreeing that DP&L did not exceed the SEET threshold for 2016 or 2017. That stipulation is pending PUCO approval. In future
years, the SEET could have a material effect on results of operations, financial condition and cash flows.
Impact of Tax Reform
On January 10, 2018 the PUCO initiated a proceeding to consider the impacts of the TCJA to determine the appropriate course of action to pass benefits resulting from the legislation on to ratepayers. The PUCO also directed Ohio utilities to record deferred liabilities for the estimated reduction in federal income tax resulting from the TCJA beginning January 1, 2018. Under the terms of the ESP, DPL will not make tax sharing payments. Under the terms of the stipulation in the distribution rate case mentioned above, DP&L
agreed to file an application at the PUCO by March 1, 2019 to refund eligible excess accumulated deferred income taxes (ADIT) and any related regulatory liability over a 10-year period. Excess ADIT related to depreciation life and method differences will be returned to customers in accordance with federal tax law and related regulations. DP&L’s rates were set using the new tax rate as a result of the distribution rate case.
FERC Proceedings
On May 8, 2018, DP&L filed to adjust its FERC jurisdictional transmission rates to reflect the effects of the decrease in federal income tax rates on the current portion of income tax expense as part of
the TCJA, resulting in a decrease of approximately $2.4 million annually. The revised rates are in effect and all DP&L over and undercollections dating back to the March 21st effective date were settled in December 2018.
On November 15, 2018 FERC issued a Notice of Proposed Rulemaking to address amortization of excess accumulated deferred income taxes resulting from the TCJA and their impact on transmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to determine the amount of excess deferred income taxes caused by the TCJA. DP&L is unable to predict the outcome
of this notice or the impact it may have on our Consolidated Financial Statements.
PJM Transmission Enhancement Settlement
On May 31, 2018, the FERC issued an Order on Contested Settlement regarding the cost allocation method for existing and new transmission facilities contained in the PJM Interconnection’s OATT. The FERC order approved
the settlement which reduces DP&L’s
transmission costs through PJM beginning in August 2018, including credits to reimburse DP&L for amounts overcharged in prior years. DP&L estimates the prior overcharge by PJM to be $41.6 million, of which approximately $14.3 million has been repaid to DP&L through December 31, 2018 and $16.5 million is classified as current in "Accounts receivable, net" and $10.8 million is classified as non-current in "Other deferred assets" on the accompanying Consolidated
Balance Sheet. All of the transmission charges and credits impacted by this FERC order are items that are included for full recovery in DP&L’s nonbypassable TCRR. Accordingly, DP&L has also established offsetting regulatory liabilities. While this development will have a temporary cash flow benefit to DP&L, there is no impact to operating income or net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018.
Regulatory Assets and Liabilities
In accordance with FASC 980, we have recognized total regulatory assets of $193.7 million
and $187.1 million at December 31, 2018 and 2017, respectively, and total regulatory liabilities of $313.2 million and $236.0 million at December 31, 2018 and 2017, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory
Assets and Liabilities.
The following table presents DPL’s Regulatory assets and liabilities:
Type of Recovery
Amortization Through
December
31,
$ in millions
2018
2017
Regulatory assets, current:
Undercollections
to be collected through rate riders
A/B
2019
$
40.5
$
23.9
Rate case expenses being recovered in base rates
B
2019
0.6
—
Total
regulatory assets, current
41.1
23.9
Regulatory
assets, non-current:
Pension benefits
B
Ongoing
87.5
92.4
Unrecovered
OVEC charges
C
Undetermined
28.7
27.8
Fuel costs
B
2020
3.3
9.3
Regulatory
compliance costs
B
2020
6.1
9.2
Smart grid and AMI costs
B
Undetermined
8.5
7.3
Unamortized
loss on reacquired debt
B
Various
6.0
7.0
Deferred storm costs
A
Undetermined
4.7
2.1
Deferred
vegetation management and other
A/B
Undetermined
7.8
8.1
Total regulatory assets, non-current
152.6
163.2
Total
regulatory assets
$
193.7
$
187.1
Regulatory
liabilities, current:
Overcollection of costs to be refunded through rate riders
A/B
2019
$
34.9
$
14.8
Total
regulatory liabilities, current
34.9
14.8
Regulatory
liabilities, non-current:
Estimated costs of removal - regulated property
Not Applicable
139.1
132.8
Deferred
income taxes payable through rates
Various
116.3
83.4
PJM transmission enhancement settlement
A
2025
16.9
—
Postretirement
benefits
B
Ongoing
6.0
5.0
Total regulatory liabilities, non-current
278.3
221.2
Total
regulatory liabilities
$
313.2
$
236.0
A – Recovery of incurred
costs plus rate of return.
B – Recovery of incurred costs without a rate of return.
C – Recovery not yet determined, but recovery is probable of occurring in future rate proceedings.
Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. DP&L is earning a net return on $5.5 million of this net deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) decoupling rider (see above), (iii) uncollectible rider and (iv) energy efficiency rider. It also includes the current portion of the following deferred costs
which are described in greater detail below: unbilled fuel, regulatory compliance rider costs and deferred storm costs. As current liabilities, this includes overcollection of: (i) competitive bidding energy and auction costs, (ii) energy efficiency program costs, (iii) alternative energy rider, (iv) economic development rider, (v) certain transmission related costs including current portion of PJM transmission enhancement settlement (see above) and (vi) reconciliation rider.
Pension benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated
operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI. As per PUCO and FERC precedents, these costs are probable of future rate recovery.
Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s fuel rider from October 2014 through October 2017. DP&L expects to recover these costs through a future rate proceeding.
Beginning on November 1, 2017, such costs are being recovered through DP&L’s Reconciliation Rider which was authorized as part of the 2017 ESP.
Fuel costs represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L was granted recovery of these costs without a return through the SSO as approved in the 2017 ESP. These costs are being recovered over the three-year period that began November 1, 2017.
Regulatory compliance rider
represents the long-term portion of the regulatory compliance rider which was established by the 2017 ESP to recover the following costs: (i) Consumer Education Campaign, (ii) Retail Settlement System, (iii) Generation Separation, (iv) Bill Format Redesign, (v) Green Pricing Tariff and (vi) Supplier Consolidated Billing. All of these costs except for Generation Separation earn a return. These costs are being recovered over a three-year period.
Rate case costs represents costs associated with preparing a distribution rate case. DP&L was granted recovery of these costs which do not earn a return, as part of the DRO.
Smart Grid and AMI costs represent costs incurred as a result of studying and developing
distribution system upgrades and implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. DP&L requested recovery of these costs as part of the December 2018 DMP filing with the PUCO described earlier.
Unamortized
loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the PUCO.
Deferred storm costs represent the long-term portion of deferred costs for major storms which occurred during 2017 and 2018. The 2017 ESP granted DP&L approval to establish a rider by which to seek recovery of these types of costs with a return. DP&L plans to file petitions seeking recovery of each calendar year of storm costs in the following calendar year. Recovery of these costs is probable by 2020, but not certain.
Estimated
costs of removal - regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.
Deferred income taxes payable through rates represent deferred income tax liabilities recognized from the normalization of flow-through items as the result of taxes previously charged to customers. A deferred income tax asset or liability is created from a difference in income recognition between tax laws and accounting methods. As a regulated utility, DP&L includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets. On December
22, 2017, the TCJA was signed, which includes a provision to, among other things, reduce the federal corporate income tax rate to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, DP&L remeasured its deferred income tax assets and liabilities using the new expected tax rate. DP&L believes that the portion of the reduction in the net deferred tax liability which is related to deferred taxes considered in ratemaking will be used in future ratemaking to reduce jurisdictional retail rates. Accordingly, this liability reflects the estimated deferred taxes DP&L expects to return to customers in future periods.
Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.
Note 4 – Property, Plant
and Equipment
The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2018 and 2017:
Composite
rates for 2017 include property classified in non-current assets of discontinued operations and held-for-sale businesses.
In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L, Duke or AEP after the transaction. This transaction also resulted in cash proceeds to DP&L of $10.6 million and no gain or loss was recorded on the transaction.
AROs
We
recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs related to Conesville, the closed Hutchings EGU, and the previously owned Beckjord Facility are recorded within Asset retirement obligations on the consolidated balance sheets. The generation AROs related to our other retired or sold generation facilities are recorded in Non-current liabilities of discontinued operations and held-for-sale
businesses on the consolidated balance sheets and are excluded from the table below. See Note 15 – Discontinued Operations for additional information.
Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.
Primarily includes settlement related to transfer of Beckjord Facility. See Note 16 – Dispositions for additional information.
See Note 5 – Fair Value for further discussion on ARO revisions to cash flow and
timing estimates.
Asset Removal Costs
We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $139.1 million and $132.8 million in estimated costs of removal at December 31, 2018 and 2017, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through
depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Matters for additional information.
Changes in the Liability for Transmission and Distribution Asset Removal Costs
The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may
not be realized in the future.
The table below presents the fair value and cost of our non-derivative instruments at December 31, 2018 and 2017. See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
•
Level 1 (quoted prices in active markets for identical assets or liabilities);
•
Level
2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or
•
Level 3 (unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.
We
did not have any transfers of the fair values of our financial instruments among Level 1, Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 2018 and 2017.
Debt
The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2019 to 2061.
Master
Trust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.6 million ($1.0 million net of tax) was reversed to Accumulated Deficit and all future changes to fair value on the
Master Trust Assets will be included in income in the period that the changes occur. These changes to fair value were not material for the year ended December 31, 2018. 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 consolidated balance sheets and classified as available for sale.
During the year ended December 31, 2018, $0.5 million ($0.4 million after tax) of various investments were sold to facilitate the distribution of benefits.
The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DPL was determined as follows:
Our financial instruments are valued using the market approach in the following categories:
•
Level 1 inputs are used 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 interest rate hedge contracts which are
valued using a benchmark interest rate. Other Level 2 assets include open-ended mutual funds in the Master Trust, which are valued using the end of day NAV per unit.
•
Level 3 inputs such as certain debt balances are considered a Level 3 input because the notes are not publicly traded. Our long-term debt is fair valued for disclosure purposes only.
All of the inputs to the fair value of our derivative instruments are from quoted market prices.
Our long-term debt is fair valued for disclosure purposes only and most of the fair
values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. As the Wright-Patterson Air Force Base note is not publicly traded, fair value is assumed to equal carrying value. 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 our long-term debt is not recorded at fair value.
Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management
estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. In 2018, DPL recorded a net reduction to its ARO liability for Conesville's ash pond and landfill of $2.6 million to reflect revisions to cash flow and timing estimates. The balance of AROs was $9.4 million and $15.1 million at December 31, 2018 and 2017, respectively, which excludes AROs associated with our discontinued operations. See Note 15 – Discontinued Operations for additional information on AROs associated with our discontinued
operations.
When evaluating impairment of long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount.
The following table summarizes major categories of assets measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
See
Note 17 – Fixed-asset Impairments for further information
(b)
Carrying amount at date of valuation
The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016:
Note 6 – Derivative Instruments and Hedging Activities
In the normal course of business, DPL enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our
net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes.
At December 31, 2018, DPL's outstanding derivative instruments were as follows:
Commodity
Accounting
Treatment (a)
Unit
Purchases (in thousands)
Sales (in thousands)
Net Purchases/ (Sales) (in thousands)
Interest Rate Swaps
Designated
USD
$
140,000.0
$
—
$
140,000.0
(a)
Refers
to whether the derivative instruments have been designated as a cash flow hedge.
At December 31, 2017, DPL's outstanding derivative instruments were as follows:
Commodity
Accounting
Treatment (a)
Unit
Purchases (in thousands)
Sales (in thousands)
Net Purchases/ (Sales) (in thousands)
FTRs (b)
Not designated
MWh
2.1
—
2.1
Natural
Gas (b)
Not designated
Dths
3,322.5
(390.0
)
2,932.5
Forward
Power Contracts (b)
Designated
MWh
678.5
(1,667.0
)
(988.5
)
Forward
Power Contracts (b)
Not designated
MWh
871.0
(765.6
)
105.4
Interest
Rate Swaps
Designated
USD
$
200,000.0
$
—
$
200,000.0
(a)
Refers
to whether the derivative instruments have been designated as a cash flow hedge.
(b)
As of December 31, 2017, the related asset and liability balances for these derivative instruments were classified in assets and liabilities of discontinued operations and held-for-sale businesses.
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair
values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were considered to determine the hedge effectiveness of the cash flow hedges. With the adoption of ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities effective January 1, 2019, we will no longer be required to calculate effectiveness and thus the entire
change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
In prior years, we entered into forward power contracts and forward natural gas 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. As of December 31, 2018, we no longer held any positions in forward power contracts or forward natural gas contracts.
We have two
interest rate swaps to hedge the variable interest on our $140.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $140.0 million and will settle monthly based on a one-month LIBOR. As of December 31, 2017, the interest rate swaps had a combined notional amount of $200.0 million. On March 29, 2018, we settled $60.0 million of these interest rate swaps due to the partial repayment of the underlying debt and a gain of $0.8 million was recorded as a reduction to interest expense. Since the swap was partially settled, the remaining swaps were de-designated
and then re-designated with a new hypothetical derivative. The AOCI associated with the remaining swaps will be amortized out of AOCI into interest expense over the remaining life of the underlying debt.
We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged
interest payments occur.
The following tables provide information on gains or losses recognized in AOCI for the cash flow hedges for the periods indicated:
Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.
Derivatives Not Designated as Hedges
In prior years certain derivative contracts were entered into on a regular basis as part of our risk management program but did not qualify
for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts were recorded at fair value with changes in the fair value charged or credited to the consolidated statements of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we entered into as part of our risk management program may have been settled financially, by physical delivery or net settled with the counterparty. We marked to market FTRs, natural gas futures and certain forward power contracts. For the years ended December 31, 2018, 2017, and 2016, all amounts related to such contracts are presented in discontinued operations. As of December 31, 2018,
we no longer have any such contracts.
Certain qualifying derivative instruments we previously held were designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of operations on an accrual basis. For the years ended December 31, 2018, 2017, and 2016, all amounts related to such contracts are presented in discontinued operations. As of December 31, 2018, we no longer have any such contracts.
The
following tables show the amount and classification within the Consolidated Statements of Operations or Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the years ended December 31, 2018, 2017 and 2016:
Recorded
in Statement of Operations: gain / (loss)
Income / (loss) from discontinued operations before income tax
$
(0.3
)
$
(3.2
)
$
2.6
$
(0.9
)
Total
$
(0.3
)
$
(3.2
)
$
2.6
$
(0.9
)
DPL
has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements.
The following tables summarize the derivative positions presented in the balance sheet where a right of offset exists under these arrangements and related cash collateral received or pledged; as well as the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments.
Note payable to related party. See Note 12 – Related Party Transactions for additional information.
At
December 31, 2018, maturities of long-term debt are summarized as follows:
Due during the years ending December 31,
$ in millions
2019
$
103.6
2020
144.7
2021
784.7
2022
422.8
2023
0.2
Thereafter
32.4
1,488.4
Unamortized
discounts and premiums, net
(1.9
)
Deferred financing costs, net
(10.6
)
Total long-term debt
$
1,475.9
Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method.
Significant
Transactions
On March 30, 2018, DPL issued a Notice of Partial Redemption to the Trustee (U.S. Bank) on the DPL 6.75% Senior Notes due 2019. DPL notified the trustee that it was calling $101.0 million of the $200.0 million outstanding principal amount of these notes. These bonds were redeemed at par plus accrued interest and a make-whole premium of $5.1 million on April 30, 2018 with cash on hand.
On March
30, 2018, DP&L commenced a redemption of $60.0 million of outstanding tax exempt First Mortgage Bonds due 2020 at par value (plus accrued and unpaid interest). These bonds were redeemed at par plus accrued interest on April 30, 2018 with cash on hand.
On March 27, 2018, DPL made a $70.0 million prepayment to eliminate the outstanding balance of its bank term loan in full. As of March 31, 2018, the term loan was fully paid off.
On January
3, 2018, DP&L and its lenders amended DP&L's Term Loan B credit agreement. The amendment (a) modified the definition of "applicable rate", from 2.25% per annum to 1.00% per annum - in the case of the Base Rate, and from 3.25% per annum to 2.00% per annum - in the case of the Eurodollar Rate, and (b) included a "call protection" provision which stated that in the event the loan was repriced or any portion of the loans were prepaid, repaid, refinanced, substituted, or replaced on or prior July 3, 2018, such prepayment, acceleration, repayment, refinancing, substitution or replacement would be made at 101%
of the principal amount so prepaid, repaid,
refinanced, substituted or replaced. After July 3, 2018 any such transaction would occur at 100% of the principal amount of the then outstanding loans. There were no such transactions prior to July 3, 2018.
Debt Covenants and Restrictions
DPL’s revolving credit agreement and term loan have two
financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down to not exceed 7.00 to 1.00 for any fiscal quarter ending January 1, 2019 through June 30, 2019; and it then steps down not to exceed 6.75 to 1.00 for any fiscal quarter ending July
1, 2019 through December 31, 2019; and it then steps down not to exceed 6.50 to 1.00 for any fiscal quarter ending January 1, 2020 and afterward. As of December 31, 2018, this financial covenant was met with a ratio of 5.84 to 1.00.
The second financial covenant is an EBITDA to Interest Expense ratio that is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreement, is to be not less than 2.10 to 1.00 for any fiscal quarter
ending September 30, 2015 through December 31, 2018; it then steps up to be not less than 2.25 to 1.00 for any fiscal quarter ending January 1, 2019 and afterward. As of December 31, 2018, this financial covenant was met with a ratio of 2.61 to 1.00.
DPL’s secured revolving credit agreement and senior unsecured notes due 2019 also restricts dividend payments from DPL to AES, such that DPL cannot make dividend payments unless at the time of, and/or as a result of the distribution,
(i) DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, if such ratios are not within the parameters, (ii) DPL’s senior long-term debt rating from two of the three major credit rating agencies is at least investment grade. As of December 31, 2018, DPL's senior-long term debt rating was at least investment grade by two of the three major credit rating agencies. However, DPL is also restricted from making dividend and tax sharing payments from DPL to AES per its 2017 ESP. This order restricts dividend
payments from DPL to AES during the term of the 2017 ESP and restricts tax sharing payments from DPL to AES during the term of the DMR. On January 22, 2019, DP&L filed a request to extend the DMR for an additional two years. See Note 3 – Regulatory Matters for more information. As a result, as of December 31, 2018, DPL was prohibited under this order from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).
DP&L’s unsecured revolving credit agreement and Bond Purchase
and Covenants Agreement (financing document entered into in connection with the sale of $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015) have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. DP&L’s Total Debt to Total Capitalization ratio shall not be greater than 0.65 to 1.00; except that, the ratio shall be suspended if DP&L’s long-term indebtedness is less than or equal to $750.0 million. Additionally, the ratio
shall be suspended any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. As of December 31, 2018, DP&L's ratings meet those requirements and this ratio is suspended for the quarter ended December 31, 2018.
The second financial covenant measures EBITDA to Interest Expense. The Total Consolidated EBITDA to Consolidated Interest Charges ratio is calculated, at the end of each fiscal quarter, by dividing consolidated
EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreement, is to be not less than 2.50 to 1.00. This covenant was met with a ratio of 8.09 to 1.00 as of December 31, 2018.
DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.As of December 31, 2018, DP&L and DPL
were in compliance with all debt covenants, including the financial covenants described above.
Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. All generation assets were released from the lien of DP&L's first and refunding mortgage in connection with the completion of Generation Separation on October 1, 2017.
DPL’s components of income tax expense on continuing operations were as follows:
Years ended December 31,
$
in millions
2018
2017
2016
Computation of tax expense / (benefit)
Federal
income tax expense / (benefit)(a)
$
6.7
$
(2.3
)
$
4.3
Increases (decreases) in tax resulting from:
State
income taxes, net of federal effect
0.1
0.1
—
Depreciation of flow-through differences
(4.6
)
1.1
3.3
Investment
tax credit amortized
(0.3
)
(0.3
)
(0.4
)
Deferred tax adjustments
—
(0.7
)
(9.3
)
Accrual
(settlement) for open tax years
—
(0.4
)
2.0
Other, net (b)
(1.2
)
(2.5
)
(2.3
)
Tax
expense / (benefit)
$
0.7
$
(5.0
)
$
(2.4
)
Components
of tax expense / (benefit)
Federal - current
$
(17.9
)
$
23.8
$
(3.3
)
State
and Local - current
0.5
0.2
—
Total current
(17.4
)
24.0
(3.3
)
Federal
- deferred
18.3
(28.8
)
0.8
State and local - deferred
(0.2
)
(0.2
)
0.1
Total
deferred
18.1
(29.0
)
0.9
Tax expense / (benefit)
$
0.7
$
(5.0
)
$
(2.4
)
(a)
The
statutory tax rate of 21% in 2018 and 35% in 2017 and 2016 was applied to pre-tax earnings.
(b)
Includes expense / (benefit) of $3.5 million and $(0.9) million in the years ended December 31, 2017 and 2016, respectively,
of income tax related to adjustments from prior years. The 2018 and 2017 tax years also include a remeasurement of deferred tax expense related to the recent enactment of the TCJA of a benefit of $(1.2) million and $(0.4) million, respectively.
Effective and Statutory Rate Reconciliation
The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DPL's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2018, 2017 and 2016:
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
The Other caption includes deferred tax assets of $10.9 million in 2018
and $9.3 million in 2017 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $10.9 million in 2018 and $9.3 million in 2017. These net operating loss carryforwards expire from 2019 to 2037.
U.S. Tax Reform
On December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law.
In 2017, we recognized the income
tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of FASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, our 2017 financial statements reflected the income tax effects of U.S. tax reform for which the accounting was complete and provisional amounts for those impacts for which the accounting under FASC 740 was incomplete, but a reasonable estimate could be determined.
We completed our calculation of the impact of the TCJA in our income tax provision for the year ended December 31, 2018 in accordance with our understanding of the TCJA and guidance available as of the date of this filing, and as a result recognized $15.5 million and $13.7
million of discrete tax expense in the fourth quarter of 2018 and 2017 respectively. Of this total, tax benefits of $1.2 million and $0.4 million are included in continuing operations in 2018 and 2017, respectively. These amounts result from the remeasurement of certain deferred tax assets and liabilities as the rates changed from 35% to 21%. The most material deferred taxes to be remeasured related to property, plant and equipment. The remeasurements of deferred tax assets and liabilities related to regulated utility property of $17.0 million and $135.2 million at December 31, 2018
and 2017 were recorded as regulatory liabilities and were non-cash adjustments.
Per the terms of the order issued by the PUCO on DP&L's 2017 ESP, DPL will not make any tax-sharing payments to AES and AES will forgo collection of the payments during the term of the DMR. The agreed upon term of the DMR is three years. With commission approval, the DMR can be extended two additional years allowing for the term to potentially be five years. Both the current and non-current existing tax sharing liabilities with AES were converted into additional equity investment in DPL, per the requirements of the order. Throughout the term of the DMR, further accrued tax sharing liabilities will also be converted
to additional equity. All parties agreed that the initial conversion and subsequent conversions will not be reversed. During the years ended December 31, 2018 and 2017, we converted $40.0 million and $97.1 million, respectively, of accrued tax sharing liabilities with AES to additional equity investment in DPL in accordance with this requirement.
The following table presents the tax expense / (benefit) related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
Of the December
31, 2018 balance of unrecognized tax benefits, $3.5 million is due to uncertainty in the timing of deductibility.
We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued and the tax expense / (benefit) recorded were not material for each period presented.
Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal – 2011 and forward
State and Local – 2011 and forward
None of the unrecognized tax benefits are expected to significantly increase or
decrease within the next twelve months other than those subject to expiring statute of limitations.
Note 9 – Benefit Plans
Defined Contribution Plans
DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.
Certain non-union and union employees become eligible to participate in their respective plan upon date
of hire.
Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,400 for 2018 and they are fully vested in their employer contributions after 3
years of service. All participants are fully vested in their own contributions.
We contributed $3.7 million, $3.1 million and $5.1 million for the years ended December 31, 2018, 2017 and 2016, respectively. DP&L matching contributions are paid quarterly, in arrears. Therefore, the contributions by year include the fourth quarter matching contribution that is paid in the following year. DP&L also contributes an annual bonus to the accounts of its union participants. This payment is typically made in January of the following year.
Defined
Benefit Plans
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan formula was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s
death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.
Almost all management employees beginning employment on or after January
1, 2011 participate in a cash balance pension plan formula. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.
In
addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners in our co-owned generating plants related to our share of their pension liabilities within Pension, retiree and other benefits on our Consolidated Balance Sheets.
We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities
which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.
Postretirement Benefits
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare.
We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $9.2 million and $12.7 million at December 31, 2018 and 2017, respectively, were not material to the consolidated financial statements in the periods covered by this report.
The following tables set forth the changes in our pension plan's obligations and assets recorded on the Consolidated Balance Sheets at December 31, 2018 and 2017. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December
31, 2018 and 2017.
$ in millions
Years ended December 31,
Change in benefit obligation
2018
2017
Benefit
obligation at January 1
$
436.9
$
419.6
Service cost
6.1
5.7
Interest
cost
13.8
14.2
Plan amendments
5.1
—
Plan
curtailment
—
3.0
Actuarial (gain) / loss
(34.6
)
28.1
Benefits
paid
(40.8
)
(33.7
)
Benefit obligation at December 31
386.5
436.9
Change
in plan assets
Fair value of plan assets at January 1
357.5
341.0
Actual return on plan assets
(11.7
)
44.8
Employer
contributions
7.9
5.4
Benefits paid
(40.8
)
(33.7
)
Fair
value of plan assets at December 31
312.9
357.5
Unfunded status of plan
$
(73.6
)
$
(79.4
)
December
31,
Amounts recognized in the Balance sheets
2018
2017
Current liabilities
$
(0.4
)
$
(0.4
)
Non-current
liabilities
(73.2
)
(79.0
)
Net liability at end of year
$
(73.6
)
$
(79.4
)
Amounts
recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost
$
9.1
$
4.9
Net
actuarial loss
103.3
111.4
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
$
112.4
$
116.3
Recorded
as:
Regulatory asset
$
87.2
$
92.1
Accumulated
other comprehensive income
25.2
24.2
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
$
112.4
$
116.3
The
accumulated benefit obligation for our defined benefit pension plans was $378.7 million and $428.3 million at December 31, 2018 and 2017, respectively.
The net periodic benefit cost of the pension plans was:
Years
ended December 31,
$ in millions
2018
2017
2016
Service cost
$
6.1
$
5.7
$
5.7
Interest
cost
13.8
14.2
14.7
Expected return on assets
(21.2
)
(22.8
)
(22.8
)
Plan
curtailment (a)
—
4.1
3.8
Amortization of unrecognized:
Actuarial
loss
6.4
5.3
4.3
Prior service cost
0.9
1.1
1.8
Net
periodic benefit cost
$
6.0
$
7.6
$
7.5
Rates
relevant to each year's expense calculations
Discount rate
3.66
%
4.28
%
4.49
%
Expected
return on plan assets
6.25
%
6.50
%
6.50
%
(a)
As a result of the decision to retire certain coal-fired plants, we recognized
a plan curtailment of $4.1 million and $3.8 million in 2017 and 2016, respectively.
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Years
ended December 31,
$ in millions
2018
2017
2016
Net actuarial loss
$
3.4
$
9.1
$
20.9
Plan
curtailment (a)
—
(4.1
)
(3.8
)
Reversal of amortization item:
Net
actuarial loss
(6.4
)
(5.3
)
(4.3
)
Prior service cost
(0.9
)
(1.1
)
(1.8
)
Total
recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
$
(3.9
)
$
(1.4
)
$
11.0
Total
recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
$
2.1
$
6.2
$
18.5
(a)
As
a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $4.1 million and $3.8 million in 2017 and 2016, respectively.
Significant Gains and Losses Related to Changes in the Benefit Obligation
The actuarial gain of $34.6 million decreased the benefit obligation for the year ended December 31, 2018 and an actuarial loss of $28.1 million increased the benefit obligation for the year ended December
31, 2017. The actuarial gain in 2018 was primarily due to an increase in the discount rate, while the actuarial loss in 2017 was primarily due to a decrease in the discount rate.
Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
At
December 31, 2018, we are maintaining our long-term rate of return assumption of 6.25% for pension plan assets. The rate of return represents our long-term assumptions based on our long-term portfolio mix. Also, at December 31, 2018, we have increased our assumed discount rate to 4.35% from 3.66% for pension expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in 2019 pension expense of approximately
$3.2 million. A one percent decrease in the rate of return assumption for pension would result in an increase in 2019 pension expense of approximately $3.2 million. A 25-basis point increase in the discount rate for pension would result in a decrease of approximately $0.1 million to 2019 pension expense. A 25-basis point decrease in the discount rate for pension would result in an increase of approximately $0.4 million to 2019 pension expense.
In
determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2018. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.
Consistent with the requirements of FASC
715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.
In future periods, differences in the actual return on pension plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any, to the plans.
The weighted average assumptions used to determine benefit obligations at December 31, 2018, 2017 and 2016 were:
Plan assets are invested using a total return investment approach whereby a mix of equity securities,
debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.
Long-term
strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations consider the plan’s long-term objectives. The long-term target allocations for plan assets are 24% – 52% for equity securities and 47% – 65% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds.
Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions
are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small target allocation in a core property fund.
Most of our plan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core Property Collective Fund is measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.
The following table summarizes our target pension plan allocation for 2018:
Long-Term Mid-Point Target Allocation
Percentage
of plan assets as of December 31,
Asset category
2018
2017
Equity Securities
38%
33%
35%
Debt
Securities
56%
58%
55%
Cash and Cash Equivalents
—%
1%
—%
Real
Estate
6%
8%
10%
The fair values of our pension plan assets at December 31, 2018 by asset category are as follows:
Fair
Value Measurements for Pension Plan Assets at December 31, 2018
Quoted prices in active markets for identical assets
Significant observable inputs
Significant unobservable inputs
Asset
category
(Level 1)
(Level 2)
(Level 3)
Mutual funds:
U.S.
equities (a)
$
79.3
$
79.3
$
—
$
—
International
equities (a)
25.9
25.9
—
—
Fixed
income (b)
143.7
143.7
—
—
Fixed
income securities:
U.S. Treasury securities
37.5
37.5
—
—
Cash
and cash equivalents:
Money market funds (c)
2.4
2.4
—
—
Other
investments:
Core property collective fund (d)
24.1
—
24.1
—
Total
pension plan assets
$
312.9
$
288.8
$
24.1
$
—
(a)
This
category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market
issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This category is comprised of investments in U.S. treasury obligations that seek to preserve principal and maintain liquidity while providing current income. The funds are valued at the assets’ amortized cost to maintain a stable per share net asset value.
(d)
This
category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
The fair values of our pension plan assets at December 31, 2017 by asset category are as follows:
Fair
Value Measurements for Pension Plan Assets at December 31, 2017
Quoted prices in active markets for identical assets
Significant observable inputs
Significant unobservable inputs
Asset
category
(Level 1)
(Level 2)
(Level 3)
Mutual funds:
U.S.
equities (a)
$
78.2
$
78.2
$
—
$
—
International
equities (a)
46.3
46.3
—
—
Fixed
income (b)
163.3
163.3
—
—
Fixed
income securities:
U.S. Treasury securities
33.5
33.5
—
—
Other
investments: (c)
Core property collective fund
36.2
—
36.2
—
Total
pension plan assets
$
357.5
$
321.3
$
36.2
$
—
(a)
This
category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This
category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
Pension Funding
We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $7.5 million to the pension plan in the year ended December 31, 2018 and $5.0 million to the pension plan in each of the years ended December 31, 2017 and 2016.
We
expect to make contributions of $0.4 million to our SERP in 2019 to cover benefit payments. We also expect to make contributions of $7.5 million to our pension plan during 2019.
Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that consider the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.
From an ERISA funding perspective, DP&L’s funded
target liability percentage was estimated to be 101%. In addition, DP&L must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be approximately $5.4 million in 2019, which includes $1.9 million for plan expenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. DP&L’s funding policy for the pension plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can
be deducted for federal income tax purposes.
Benefit payments, which reflect future service, are expected to be paid as follows:
Estimated future benefit payments
$
in millions due within the following years:
Pension
2019
$
26.7
2020
$
26.5
2021
$
26.3
2022
$
26.0
2023
$
25.9
2024
- 2028
$
125.1
Note 10 – Equity
Redeemable Preferred Stock of Subsidiary
On October 13, 2016 (the "Redemption Date"), DPL's subsidiary, DP&L redeemed all of its issued
and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of
$103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist. The difference between the carrying value of the Redeemable Preferred Stock of Subsidiary and the redemption amount was charged to Other paid-in capital.
Dividend Restrictions
DPL’s Amended Articles of Incorporation (the Articles) contain provisions which state that DPL
may not make a distribution to its shareholder or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no Event of Default (as defined in the Articles) and no such Event of Default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, (b)(ii) if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions
to a shareholder and the making of loans to its affiliates (other than subsidiaries) cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions. DPL is also restricted from making dividend and tax sharing payments from DPL to AES per its 2017 ESP. This order restricts dividend payments from DPL to AES during the term of the ESP and restricts tax sharing payments from DPL to AES during the term of the DMR.
Common Stock
Effective on the Merger date, DPL's
Amended Articles of Incorporation provided for 1,500 authorized common shares, of which one share is outstanding at December 31, 2018.
As described above, DPL’s Amended Articles of Incorporation contain restrictions on DPL’s ability to make dividends, distributions and affiliate loans (other than to its subsidiaries), including restrictions on making such dividends, distributions and loans if certain financial ratios exceed specified levels and DPL’s senior long-term debt rating from a rating agency is below investment grade. As of December
31, 2018, DPL’s leverage ratio was at 1.47 to 1.00 and DPL’s senior long-term debt rating from a major credit rating agency was below investment grade. As a result, as of December 31, 2018, DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).
DP&L has 50,000,000 authorized common shares, of which 41,172,173 are outstanding at December
31, 2018. All common shares are held by DP&L’s parent, DPL.
Capital Contributions from AES
In DP&L's approved six-year 2017 ESP, the PUCO imposed restrictions on DPL making dividend payments to its parent company, AES, during the term of the ESP, as well as on making tax-sharing payments to AES during the
term
of the DMR. The PUCO also required that existing tax payments owed by DPL to AES, and similar tax payments that accrue during the term of the DMR, be converted into equity investments in DPL.
As such, AES agreed to make non-cash capital contributions of $97.1 million and waive the amount owed to it by DPL related to tax-sharing payments for current tax liabilities through December 31, 2017. For the year ended December 31, 2018, AES made capital contributions of $40.0 million by converting the amount owed to it by DPL related
to tax-sharing payments for current tax liabilities. See Note 8 – Income Taxes for additional information.
Note 11 – Contractual Obligations, Commercial Commitments and Contingencies
Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiary, AES Ohio Generation, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to this subsidiary on a stand-alone
basis, thereby facilitating the extension of sufficient credit to accomplish this subsidiary's intended commercial purposes.
At December 31, 2018, DPL had $23.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of AES Ohio Generation to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. We had no outstanding balance of obligations for commercial transactions covered
by these guarantees at December 31, 2018. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.9 million at December 31, 2017.
To date, DPL has not incurred any losses related to these guarantees and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.
Equity Ownership Interest
DP&L has a 4.9%
equity ownership interest in OVEC which is recorded using the cost method of accounting under GAAP. At December 31, 2018, DP&L could be responsible for the repayment of 4.9%, or $68.1 million, of a $1,389.6 million debt obligation comprised of both fixed and variable rate securities with maturities between 2019 and 2040. OVEC could also seek additional contributions from us to avoid a default in the event that other OVEC members defaulted on their respective OVEC obligations. One of the other OVEC members, with a 4.85% interest in OVEC, filed for bankruptcy
protection and the bankruptcy court approved that member's rejection of the OVEC arrangement and its related obligations on July 31, 2018. We do not expect these events to have a material impact on our financial condition, results of operations or cash flows.
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2018, these include:
Payments
due in:
$ in millions
Total
Less than 1 year
2 - 3 years
4 - 5 years
More than 5 years
Electricity purchase commitments
$
209.4
$
139.5
$
69.9
$
—
$
—
Purchase
orders and other contractual obligations
$
40.2
$
11.4
$
14.8
$
14.0
$
—
Electricity
purchase commitments:
DPL enters into long-term contracts for the purchase of electricity. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.
Purchase orders and other contractual obligations:
At December 31, 2018, DPL had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and DPL's ability to terminate
such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged
liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2018, cannot be reasonably determined.
Environmental Matters
DPL’s facilities and operations are subject to a wide range of federal, state and local environmental laws, rules and regulations. The environmental issues that may affect us include the following.
However, as described further below, as a result of DPL’s retirement of its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations, the planned 2020 retirement of Conesville and our exiting of our generation business, certain of these environmental regulations and laws are now not expected to have a material impact on DPL with respect to these generating stations.
•
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, the Ohio EPA or other authorities that require or will require substantial reductions in SO2, particulates, mercury, acid gases, NOx, and other air emissions.
•
Rules
and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs;
•
Rules and future rules issued by the USEPA, the Ohio EPA or other authorities associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits; and
•
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority
of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.
In addition to imposing continuing compliance obligations, these laws, rules 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 laws, rules and regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters
for which we have not accrued loss contingencies because the risk of loss is not probable, or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.
We have several pending environmental matters associated with our current and previously owned and operated coal-fired generation units. Some of these matters could have material adverse impacts on our results of operations, financial condition or cash flows.
Note 12 –
Related Party Transactions
Service Company
The Service Company allocates the costs for services provided based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.
DPL
participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.
Long-term Compensation Plan
During 2018, 2017 and 2016, many of DPL’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention
tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2018, 2017 and 2016 was $0.4 million, $0.4 million and $0.5 million, respectively, and was included in “Other Operating Expenses” on DPL’s Consolidated Statements of Operations. The
value of these benefits is being recognized over the 36-month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on DPL’s Consolidated Balance Sheets in accordance with FASC 718 “Compensation - Stock Compensation.”
The following table provides a summary of our related party transactions:
DPL has a wholly-owned business trust, DPL Capital Trust II (the
Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounted to $0.2 million and $0.3 million at December 31, 2018 and 2017, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $15.6
million and $15.6 million at December 31, 2018 and 2017, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 7 – Long-term debt for additional information.
In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.
Income Taxes
AES
files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. Effective with the approval of DP&L's 2017 ESP, DPL is restricted from making tax sharing payments to AES throughout the term of the DMR and amounts that would otherwise have been tax sharing liabilities are considered deemed capital contributions. See Note 8 – Income Taxes for more information.
Note
13 – Business Segments
Beginning with the second quarter of 2018, DPL has presented the results of operations of Miami Fort Station, Zimmer Station, the Peaker Assets, Stuart Station and Killen Station as discontinued operations as a group of components for all periods presented. For more information, see Note 15 – Discontinued Operations of Notes to DPL's Consolidated Financial Statements. AES Ohio Generation now only has operating activity coming from its
undivided ownership interest in Conesville, which does not meet the threshold to be a separate reportable operating segment. Because of this, DPL now manages its business through only one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The Utility segment is discussed further below:
Utility Segment
The
Utility segment is comprised primarily of DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers. DP&L distributes electricity to more than 525,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and
regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The Utility segment includes revenues and costs associated with our investment in OVEC and the historical results of DP&L’s Beckjord Facility, which was closed in 2014 and transferred to a third party in the first quarter of 2018, and the Hutchings EGU, which was closed in 2013. These assets did not transfer to AES Ohio Generation as part of DP&L's Generation Separation on October 1, 2017. Thus, they are grouped within the Utility segment for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the Utility segment.
Included within the “Other”
column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s long-term debt and adjustments related to purchase accounting from the Merger. DPL's undivided interest in Conesville is now included within the "Other" column as it no longer meets the requirement for disclosure as a reportable operating segment, since the results of operations of the other generation plants are now presented as discontinued operations. The accounting policies of the reportable segments are the same as those described in Note 1 – Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation. Certain shared and corporate costs are allocated among reporting segments.
The
following tables present financial information for DPL’s reportable business segment:
Income
/ (loss) from continuing operations before income tax
$
143.0
$
(130.6
)
$
—
$
12.4
Cash
capital expenditures
$
83.4
$
65.1
$
—
$
148.5
Total
assets (end of year)
$
1,710.5
$
1,145.9
$
(437.2
)
$
2,419.2
(a)
"Other"
includes Cash capital expenditures and Total assets related to the assets of discontinued operations and held-for-sale businesses for all periods presented.
Note 14 – Revenue
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental
authorities.
Retail Revenues – DP&L energy sales to utility customers are based on the reading of meters at the customer's location that occurs on a systematic basis throughout the month. DP&L sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Performance obligations for retail revenues are satisfied over time as energy is delivered and the same method is used to measure progress, and thus the performance obligation meets the criteria to be considered a series. This includes both the promise to transfer energy and other distribution and/or transmission services.
In exchange for the exclusive right to sell or distribute
electricity in our service area, DP&L is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that DP&L is allowed to charge customers for electricity. Since tariffs are approved by the regulator, the price that DP&L has the right to bill corresponds directly with the value to the customer of DP&L's performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff.
In cases where a customer chooses to receive generation services from a CRES provider, the price for generation services is negotiated
between the customer and the CRES provider, and DP&L only serves as a billing agent if requested by the CRES provider. As such, DP&L recognizes the consolidated billing arrangement with the CRES provider on a net basis, thereby recording no revenue for the generation component. Retail revenue from these customers would only be related to transmission and distribution charges.
Wholesale Revenues – All of the power produced from DPL's
ownership interest in Conesville and DP&L's share of the power produced at OVEC is sold to PJM and these are classified as Wholesale revenues.
In PJM, the promise to sell energy as wholesale revenue is separately identifiable from participation in the capacity market and the two products can be transacted independently of one another. Therefore, wholesale revenues are a separate contract with a single performance obligation. Revenue is recorded based on the quantities (MWh) delivered in each hour during each month at the spot price, making the contract effectively “month-to-month”.
RTO Revenues – Compensation for use of DP&L’s
transmission assets and compensation for various ancillary services are classified as RTO revenues. As DP&L owns and operates transmission lines in southwest Ohio within PJM, demand charges collected from network customers by PJM are then allocated to the appropriate transmission owners (i.e. DP&L) and recognized as transmission revenues. Additionally, as an owner of generation and transmission assets within PJM, DPL is compensated for various ancillary services; such as reactive supply, regulation services, scheduling reserves, operating reserves, spinning/synchronized reserves as well as congestion credits that are provided to PJM via these assets.
Transmission revenues have a single performance obligation, as transmission services
represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that DP&L, as the transmission operator, has the right to bill (received as a credit from PJM) corresponds directly with the value to the customer of performance completed in each period, as the price paid is the allocation of the tariff rate (as approved by the regulator) charged to network participants.
Ancillary service revenues have a single performance obligation, as they represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that
DPL has the right to bill corresponds directly with the value to the customer of performance completed in each period as the price paid is at the market price or allocation of the tariff rate (which was approved by the regulator) charged to network participants.
RTO Capacity Revenues – Compensation received from PJM for making installed generation capacity available to satisfy system integrity and reliability requirements is classified as RTO capacity revenues. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. If plant availability exceeds a contractual target, we may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent
a form of variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal and therefore the transaction price is recognized on an output basis based on the MWs.
RTO capacity revenues have a single performance obligation, as capacity is a distinct good. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The capacity price is set through a competitive auction process established by PJM.
DPL's
revenue from contracts with customers was $743.8 million for the year ended December 31, 2018. The following table presents our revenue from contracts with customers and other revenue by segment for the year ended December 31, 2018:
Other
retail revenue primarily includes alternative revenue programs not accounted for under FASC 606.
(b)
Other revenues from contracts with customers primarily includes revenues for various services provided by Miami Valley Lighting.
The balances of receivables from contracts with customers were $72.6 million and $63.0 million as of December 31, 2018 and January 1, 2018, respectively.
Payment terms for all receivables from contracts with customers are typically within 30 days.
We have elected to apply the optional disclosure exemptions under FASC 606. Therefore, we have no disclosures pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled for DPL.
Note
15 – Discontinued Operations
On December 8, 2017, DPL and AES Ohio Generation completed the sale transaction of their entire undivided interest in the Miami Fort Station and the Zimmer Station, which resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. On March 27, 2018, DPL and AES Ohio Generation completed the sale transaction of the Peaker assets to Kimura Power, LLC, which resulted in a loss on sale of $1.9 million for the year ended December
31, 2018. Further, on May 31, 2018, DPL and AES Ohio Generation retired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, as planned. Consequently, in the second quarter of 2018, DPL determined that the disposal of this group of components as a whole represents a strategic shift by us to exit generation, and, as such, qualifies to be presented as discontinued operations. Therefore, the results of operations and financial position for this group of components were reported as such in the Consolidated Statements of Operations and Consolidated Balance Sheets for all periods presented.
Previously, on January
1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015, and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. DPL recorded a gain on this transaction of $49.2 million in the first quarter of 2016. The gain included the impact of DPLER’s liability to DP&L that transferred with the sale on January 1, 2016. As such, the results of operations of DPLER were also reported as discontinued operations in the Consolidated Statements of Operations for
the year ended December 31, 2016.
Total assets of the disposal group classified as assets of discontinued operations and held-for-sale businesses in the balance sheets
$
14.0
$
321.9
Accounts
payable
$
3.9
$
25.1
Accrued taxes
3.1
6.3
Other
current liabilities
5.2
30.0
Long-term debt (a)
—
0.3
Deferred
taxes (b)
(39.8
)
(2.3
)
Taxes payable
2.3
7.4
Pension,
retiree and other benefits
9.7
10.6
Asset retirement obligations
90.4
116.6
Other
deferred credits
6.6
5.9
Total liabilities of the disposal group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets
$
81.4
$
199.9
(a)
Long-term
debt relates to capital leases.
(b)
Deferred taxes represent the tax asset position of the discontinued group of components, which were netted with liabilities on DPL prior to classification as discontinued operations.
The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated:
Years
ended December 31,
$ in millions
2018
2017
2016
Revenues
$
158.6
$
492.9
$
593.0
Cost
of revenues
(74.3
)
(249.5
)
(349.6
)
Operating and other expenses
(13.8
)
(195.0
)
(214.6
)
Fixed-asset
impairment
—
(175.8
)
(835.2
)
Income / (loss) from discontinued operations
70.5
(127.4
)
(806.4
)
Gain
/ (loss) from disposal of discontinued operations
(1.6
)
14.0
49.2
Income tax expense / (benefit) from discontinued operations
30.0
(20.3
)
(257.2
)
Net
income / (loss) from discontinued operations
$
38.9
$
(93.1
)
$
(500.0
)
Cash flows
related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(6.8) million, $126.8 million and $92.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. Cash flows from investing activities for discontinued operations were $233.8 million, $51.8 million and $(56.8) million for the years ended December 31, 2018, 2017 and 2016,
respectively.
The PUCO authorized DP&L to maintain long-term debt of $750.0 million or 75% of its rate base, whichever is greater, until January 1, 2018, or to file an application to explain why it would not achieve those metrics. Accordingly, $750.0 million of debt and the pro rata interest expense associated with that debt were allocated to continuing operations. All remaining interest expense is included in the discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years December
31, 2017 and 2016, respectively.
AROs of Discontinued Operations
DPL's retired Stuart and Killen generating facilities continue to carry ARO liabilities consisting primarily of river intake and discharge structures, coal unloading facilities, landfills, and ash disposal facilities. In the fourth quarter of 2018, DPL reduced the ARO liability related to the Stuart and Killen ash ponds and landfills by $27.6 million based on updated internal analyses that reduced estimated closure costs associated with these ash ponds and landfills. The remaining ARO liability related to Stuart and Killen is included in the AROs in the total liabilities
of the disposal
group classified as liabilities of discontinued operations and held-for-sale businesses in the balance sheets as of December 31, 2018 above. As these plants are no longer in service, the reduction to the ARO liability was also recorded as a credit to depreciation and amortization expense in the same amount. The credit to depreciation and amortization expense is included in operating and other expenses of discontinued operations for the year ended December 31, 2018 in the table above.
Note
16 – Dispositions
Beckjord Facility – On February 26, 2018, DP&L and its co-owners of the retired Beckjord Facility agreed to transfer their interests in the retired Facility to a third party, including their obligations to remediate the Facility and its site, and the transfer occurred on that same date. As a result, DPL recognized a loss on the transfer of $11.7 million and made cash expenditures of $14.5 million, inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from
continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018, 2017 and 2016, excluding the loss on transfer noted above. Prior to the transfer, the Beckjord Facility was included in the Utility segment.
Note 17 – Fixed-asset impairments
During the fourth quarter of 2016, we tested the recoverability of our long-lived coal-fired generation assets.
Lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. We performed a long-lived asset impairment analysis for the Conesville asset group and determined that its carrying amount was not recoverable. The Conesville coal-fired facility asset group was determined to have a fair value of $1.1 million using the income approach. As a result, DPL recognized a total pre-tax asset impairment expense of $23.9 million.
During the year ended December 31, 2018, DPL recognized a
total pre-tax asset impairment expense of $2.8 million for the Conesville asset group, as it was determined that additional amounts capitalized in 2018 were not recoverable.
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of The Dayton Power & Light Company
Opinion on the Financial Statements
We
have audited the accompanying balance sheets of The Dayton Power & Light Company (the Company) as of December 31, 2018 and 2017, the related statements of operations, comprehensive income/(loss), cash flows and shareholder’s equity for each of the three years in the period ended December 31, 2018, and the related notes and schedule (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity
with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Transfer
of generation assets to subsidiary of parent (c)
(10.0
)
(10.0
)
Capital
contribution from parent
80.0
80.0
Other
(d)
(0.2
)
(1.1
)
1.0
(0.3
)
Ending
balance
41,172,173
$
0.4
$
711.8
$
(35.3
)
$
(231.6
)
$
445.3
(a)
$0.01
par value, 50,000,000 shares authorized.
(b)
In 2017, we reclassified the presentation of the December 2016 dividend payment of $70.0 million. This was originally recorded as a charge to Accumulated deficit but was reclassified as a charge to Other paid-in capital as it represented a return of capital.
(c)
In 2018, DP&L transferred additional deferred
taxes to AES Ohio Generation under the provisions of SAB 118 through an equity transaction with DPL. See Note 8 – Income Taxes for additional information.
(d)
ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments.
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 consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however transmission and distribution services are still regulated. DP&L has the exclusive right to provide such service to its approximately 525,000 customers located in West Central Ohio. DP&L provides retail SSO electric service
to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Since January 2016, DP&L has been sourcing all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in multiple coal-fired power stations and multiple peaking electric generating facilities as well as numerous transmission facilities. On October 1, 2017, the DP&L-owned generating facilities, excluding the Beckjord Facility and Hutchings EGU,
were transferred to AES Ohio Generation, an affiliate of DP&L and wholly-owned subsidiary of DPL, through an asset contribution agreement to a subsidiary that was merged into AES Ohio Generation. Also, Stuart Station Unit 1 was retired on October 1, 2017. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. Through the date of Generation Separation, DP&L sold energy and capacity into the wholesale market.
As a result of Generation Separation, DP&L now only has one reportable segment, Transmission and Distribution. In addition to DP&L's electric transmission and distribution businesses, the Transmission and Distribution segment includes revenues and costs associated with DP&L's investment in OVEC and the historical results of DP&L’s Beckjord and Hutchings Coal generating facilities, which were either closed or sold in prior periods.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated
operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs or overcollections of riders.
DP&L employed 647 people at January 31, 2019. Approximately 58% of all employees are under a collective bargaining agreement.
Financial Statement Presentation
DP&L does not have any
subsidiaries.
Through June 2018, DP&L had undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities were accounted for on a pro rata basis in the Financial Statements. In June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L, Duke or AEP after the transaction. See Note 4 – Property, Plant and Equipment for more information.
We
have evaluated subsequent events through the date this report is issued.
Certain amounts from prior periods have been reclassified to conform to the current period presentation.
The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income
taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange
for those goods or services. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our Statements of Operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.
The power sales and purchases within DP&L’s service territory are reported on a net
hourly basis as revenues or purchased power on our Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred. For additional information, see Note 13 – Revenue.
Allowance for Uncollectible Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.
Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-owned
transmission and distribution property as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators AFUDC and capitalized interest was $0.5 million, $1.5 million and $2.0 million for the years ended December 31,
2018, 2017 and 2016, respectively.
For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization, consistent with composite depreciation practices.
Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.
Repairs and Maintenance
Costs associated with maintenance activities are recognized at the time the work is performed. These costs,
which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s transmission and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 3.0% in 2018, 3.4%
in 2017 and 4.6% in 2016. Depreciation expense was $68.2 million, $69.6 million and $64.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.
Regulatory Accounting
As a regulated utility, DP&L applies the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting
practices of the PUCO and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to
customers for previous over collections or the deferral of revenues collected for costs that DP&L
expects to incur in the future.
The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current
based on the term in which recovery is expected See Note 3 – Regulatory Matters for more information.
Inventories
Inventories are carried at average cost and include materials and supplies used for utility operations.
Intangibles
Intangibles include software, emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating
income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired.
Software is amortized over seven years Amortization expense was $6.3 million, $5.7 million and $6.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. The estimated amortization expense of this internal-use
software over the next five years is $11.1 million ($3.5 million in 2019, $2.4 million in 2020, $2.2 million in 2021, $1.8 million in 2022 and $1.2 million in 2023).
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions
have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Statement of Operations.
Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liability with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment See Note 3 – Regulatory Matters for additional information.
DP&L
files U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach See Note 8 – Income Taxes for additional information.
Financial Instruments
Our Master Trust investments in debt and equity financial instruments of publicly traded entities are classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on these securities are recorded in Other income. As these financial instruments are held to be used for the benefit of
employees participating in employee benefit plans and are not used for general operating purposes, they are classified as non-current in Other deferred assets on the Consolidated Balance Sheets.
A business classified as held-for-sale is reflected on the balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the carrying amount of the business exceeds its estimated fair value less cost to sell. This loss is limited to the carrying value of long-lived assets until the completion of
the sale, at which point, any additional loss is recognized. If the fair value of the business subsequently exceeds the carrying amount while the business is still held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the previously recognized expense or the subsequent excess.
Assets and liabilities related to a business classified as held-for-sale are segregated in the current balance sheet in the period in which the business is classified as held-for-sale. Assets and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within twelve months. Transactions between the business held-for-sale and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See Note
14 – Generation Separation for further information.
Discontinued Operations
Discontinued operations reporting occurs only when the disposal of a business or a group of assets represents a strategic shift that has (or will have) a major effect on our operations and financial results. We report financial results for discontinued operations separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing operations. Prior period amounts in the statement of operations and balance sheet are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued operations are included within the relevant categories within operating, investing and financing activities on the face of the
Statements of Cash Flows.
Transactions between the businesses determined to be discontinued operations and businesses that are expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or adjustment of the carrying amount to fair value. See Note 14 – Generation Separation for further information.
Generation Separation
With the transfer of DP&L's generation assets to an affiliate (see Note 14 – Generation Separation),
DP&L's generation business is presented as a discontinued operation and the operating activities have been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017 and 2016 and in the notes to the financial statements.
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements
of Operations. The amounts for the years ended December 31, 2018, 2017 and 2016 were $51.7 million, $49.4 million and $50.9 million, respectively.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Restricted Cash
Restricted
cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral and cash collected under the DMR which is restricted to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission and distribution infrastructure.
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Balance Sheet that reconcile to the total of such amounts as shown on the Statements of Cash Flows:
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction.
We use interest rate hedges to manage the interest rate risk of our variable rate debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset
such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 – Derivative Instruments and Hedging Activities for additional information.
Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us and other DPL subsidiaries for workers’ compensation, general liability, and property damage on an ongoing basis. DP&L is responsible for
claims costs below certain coverage thresholds of MVIC and third-party insurers for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, disability, and other reserves for claims costs below certain coverage thresholds of third-party providers of approximately $4.3 million and $4.4 million at December 31, 2018 and 2017, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions.
There is uncertainty associated with these loss estimates, and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.
Pension and Postretirement Benefits
We recognize in our Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes from actuarial gains or losses related to our regulated operations, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. Such changes that are not related to our regulated operations are recognized in AOCI. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting
guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of FASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.
See Note 9 – Benefit Plans for more information.
Related
Party Transactions
In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES. See Note 12 – Related Party Transactions for additional information on Related Party Transactions.
The following table provides a brief description of recently adopted accounting pronouncements
that had an impact on our consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on our financial statements.
Accounting Standard
Description
Date of Adoption
Effect on the financial statements upon adoption
New Accounting Standards Adopted
2018-15,
Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract
This standard aligns the accounting for implementation costs incurred for a cloud computing arrangement that is a service with the requirement for capitalizing implementation costs associated with developing or obtaining internal-use software. Transition method: retrospective or prospective.
We elected to early-adopt this standard on a prospective basis, effective for fiscal year 2018. The adoption of this standard did not have a material impact on our financial statements.
2018-14,
Compensation— Retirement Benefits — Defined Benefit Plans — General (Subtopic 715-20): Disclosure Framework
This standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. Transition method: retrospective.
Impact limited to changes in financial statement disclosures.
2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
This standard changes the presentation of non-service costs
associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. Transition method: retrospective for presentation of non-service cost and prospective for the change in capitalization.
For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Other expense of ($1.5) million and ($0.9) million, respectively.
2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)
This
standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Transition method: retrospective.
For the years ended December 31, 2017 and 2016, we reclassified from "Net cash used in investing activities" to "Net increase / (decrease) in cash, cash equivalents and restricted
cash" $26.6 million and ($11.9) million, respectively.
2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
The standard significantly revises an entity’s accounting related to (1) classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosures of financial instruments. Transition method: modified retrospective. Prospective for equity investments without readily determinable fair value.
We adopted this standard
January 1, 2018. At that date, we transferred $1.7 million ($1.1 million net of tax) of unrealized gains from AOCI to Retained Earnings.
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-10, 2017-13, Revenue from Contracts with Customers (Topic 606)
Adoption of FASC Topic 606, "Revenue from Contracts with Customers"
On January
1, 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers", and its subsequent corresponding updates ("FASC 606"). The core principle of this standard is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We applied the modified retrospective method of adoption to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018 are presented under FASC 606, while prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting under the previous revenue recognition standard. For contracts that were modified before January
1, 2018, we have not retrospectively restated the contracts for modifications. We instead reflected the aggregate effect of all modifications when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis.
There was no cumulative effect to our January 1, 2018 Balance Sheet resulting from the adoption of FASC 606.
New
accounting pronouncements issued but not yet effective - The following table provides a brief description of recent accounting pronouncements that could have a material impact on our financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on our financial statements.
Accounting Standard
Description
Date of Adoption
Effect on the financial statements
upon adoption
New Accounting Standards Issued but Not Yet Effective
2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from AOCI
This amendment allows a reclassification of the stranded tax effects resulting from the implementation of the Tax Cuts and Jobs Act from AOCI to retained earnings. Because this amendment only relates to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected.
We do not expect any impact on our financial statements upon adoption of the standard on January 1, 2019.
2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities
The standard updates the hedge accounting model to expand the ability to hedge nonfinancial and financial risk components, reduce complexity, and ease certain documentation and assessment requirements. When facts and circumstances are the same as at the previous quantitative test, a subsequent quantitative effectiveness test is not required. The standard also eliminates the requirement to separately measure and report hedge ineffectiveness. For cash flow hedges, this means that the entire
change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item in the period in which it settles. Transition method: modified retrospective with the cumulative effect adjustment recorded to the opening balance of retained earnings as of the initial application date. Prospective for presentation and disclosures.
We are currently evaluating the impact of adopting the standard on our financial statements.
2018-19, 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments
The
standard updates the impairment model for financial assets measured at amortized cost. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowance for losses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses as it is done today, except that the losses will be recognized as an allowance rather than a reduction in the amortized cost of the securities. Transition method: various.
We will adopt the standard on January 1, 2019; see below for the evaluation of the impact of its adoption on our financial statements.
Adoption of FASC Topic 842, "Leases"
ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities
for most leases but recognize expenses in a manner similar to today’s accounting. For lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions.
The standard must be adopted using a modified retrospective approach. The FASB has provided an optional transition method, which we have elected, that allows entities to continue to apply the guidance in FASC 840 Leases to the comparative periods presented in the year of adoption. Under this transition method, we will apply the transition provisions starting on January 1, 2019.
We have elected to apply a package of practical expedients that allow lessees and lessors
not to reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization under FASC 842. These three practical expedients must be elected as a package and must be consistently applied to all leases. We have also elected to apply an optional transition practical expedient for land easements that allows an entity to
continue applying its current accounting policy for all land easements that exist before the standard’s effective date that were not previously accounted for under FASC 840.
We
established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use assets and related liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool that will support the implementation and the subsequent accounting. The implementation team has also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of the real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will recognize
a lease receivable. According to FASC 842, the lease receivable includes the fair value of the plant after the contract period but does not include any variable payments such as margin on the sale of energy. Therefore, the lease receivable could be significantly different than the carrying amount of the underlying asset at lease commencement. In such circumstances, the difference between the initially recognized lease receivable and the carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.
The adoption of FASC 842 did not have a material impact on our financial statements.
Note 2 – Supplemental
Financial Information
December 31,
$ in millions
2018
2017
Accounts
receivable, net
Customer receivables
$
53.3
$
44.2
Unbilled
revenue
16.8
18.0
Amounts due from partners in jointly-owned stations
—
5.0
Due
from PJM transmission enhancement settlement (a)
16.5
—
Due from affiliates
2.3
0.6
Other
2.4
4.1
Provisions
for uncollectible accounts
(0.9
)
(1.1
)
Total accounts receivable, net
$
90.4
$
70.8
Inventories,
at average cost
Materials and supplies
$
7.1
$
6.9
Other
0.6
0.4
Total
inventories, at average cost
$
7.7
$
7.3
(a) - See Note 3 – Regulatory Matters for more information.
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2018, 2017 and 2016 are as follows:
Details
about Accumulated Other Comprehensive Income / (Loss) Components
Affected line item in the Statements of Operations
Years ended December 31,
$ in millions
2018
2017
2016
Gains
and losses on equity securities activity (Note 5):
Other deductions
$
—
$
(0.1
)
$
—
Income
tax expense
—
—
—
Net of income taxes
—
(0.1
)
—
Gains
and losses on cash flow hedges (Note 6):
Interest expense
(1.1
)
(0.9
)
(1.0
)
Income
tax benefit
0.4
0.2
0.2
Net of income taxes
(0.7
)
(0.7
)
(0.8
)
Loss
from discontinued operations
—
(8.5
)
(45.4
)
Income tax benefit from discontinued operations
—
3.0
16.2
Net
of income taxes
—
(5.5
)
(29.2
)
Amortization
of defined benefit pension items (Note 9):
Other income
4.3
6.8
7.7
Income
tax expense
(1.0
)
(2.3
)
(1.8
)
Net of income taxes
3.3
4.5
5.9
Total
reclassifications for the period, net of income taxes
$
2.6
$
(1.8
)
$
(24.1
)
The
changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2018 and 2017 are as follows:
ASU
2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments.
Note 3 – Regulatory Matters
Distribution Rate Order
On September 26, 2018 the PUCO issued the DRO establishing new base distribution rates for
DP&L, which became effective October 1, 2018. The DRO approved, without modification, a stipulation and recommendation previously filed by DP&L, along with various intervening parties and the PUCO staff. The DRO established a
revenue requirement of $248.0 million for DP&L's electric service base distribution rates which reflects an increase to distribution revenues
of approximately $29.8 million per year. In addition to the increase in base distribution rates, and among other matters, the DRO provides for a return on equity of 9.999% and a cost of long-term debt of 4.8% and for the following items:
DIR – The DRO authorized DP&L to begin charging a Distribution Investment Rider ("DIR") set initially at $12.2 million annually, effective October 1, 2018. The DIR revenue requirement shall be updated quarterly and will increase as DP&L makes
qualified investments in its distribution network, subject to annual revenue limits which increase each year; the revenue limit for 2019 is $22.0 million. The DIR will expire in November 2022 unless DP&L files a base distribution rate case on or before October 31, 2022, in which case the DIR will expire in November 2023.
Decoupling Rider – The DRO eliminated provisions in the existing decoupling rider which allowed DP&L to recover lost revenues resulting from the implementation of energy efficiency programs and replaced it with a revenue requirement that attempts to eliminate the impacts of weather and demand on DP&L’s
revenues from residential and commercial distribution customers beginning January 1, 2019. As a result, in years with very mild weather and/or decreased demand, DP&L will be able to accrue a regulatory asset for recovery through the rider to normalize the revenues. Conversely, in periods of extreme temperatures or high demand for electricity, DP&L may record a liability for future reimbursement to customers. The rider also includes a one-time $3.7 million revenue requirement based on the increase in the number of DP&L’s residential and commercial customers from the rate case test year until September 30, 2018. Such amount was accrued and included in revenues in the third quarter
of 2018 and will be collected by DP&L in 2019.
TCJA – The DRO partially resolved the TCJA impacts. The new distribution rates include the impacts of the decrease in current federal income taxes beginning October 1, 2018. The DRO did not designate how much DP&L may owe for any overcollection of taxes from January 1, 2018 through September 30, 2018, nor did it resolve any decrease in future rates related to amortization of excess accumulated deferred income taxes (“ADIT”). The DRO did, however, stipulate that DP&L must refund its customers an amount no
less than $4.0 million per year for the first five years of the amortization period unless all balances owed are fully returned within the first five years. For more on the impacts of the TCJA, see below.
Vegetation Management Costs – The DRO authorizes DP&L to defer as a regulatory asset, with no carrying costs, annual expenses for vegetation management performed by third-party vendors. For calendar year 2018 annual expenses which are incremental to the baseline of $10.7 million can be deferred up to a $4.6 million cap. For calendar years 2019 and thereafter, annual expenses in excess of $15.7 million can be deferred up to
a $4.6 million annual cap. Annual spending of less than the vegetation management baseline amounts will result in a reduction to the regulatory asset or creation of a regulatory liability. For 2018, DP&L accrued a regulatory asset for the maximum amount of $4.6 million based upon such provisions and spending above the baseline.
In December 2018, DP&L filed a Distribution Modernization Plan (“DMP”) with the PUCO proposing to invest $576.0 million in capital projects over the next 10 years. There are eight principal components of DP&L’s DMP: 1) Smart Meters, 2) Self-Healing Grid, 3) Customer
Engagement, 4) Enhancing Sustainability and Embracing Innovation. 5) Telecommunications, 6) Physical and Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D.
ESP Order
On March 13, 2017, DP&L filed an amended stipulation to its 2017 ESP, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The six-year 2017 ESP establishes DP&L's framework for providing retail service on a going-forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms which
include, but are not limited to, the following:
•
Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;
•
The establishment of a three-year non-bypassable Distribution Modernization Rider (DMR) designed to collect $105.0 million in revenue per year to pay debt obligations at DPL and DP&L
and position DP&L to modernize and/or maintain its transmission and distribution infrastructure with an option for DP&L to file for an extension of the rider for an additional two years in an amount subject to approval by the PUCO.
Consistent with that settlement and the PUCO order, on January 22, 2019, DP&L filed a request to extend the DMR for the additional two years at an annual revenue amount of $199.0 million.
That request is pending PUCO review;
•
The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which was established in the DP&L DRO;
•
A non-bypassable Reconciliation Rider permitting DP&L to defer, recover or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment
in OVEC and DP&L's OVEC related costs;
•
Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new, or changes to existing, rates, riders and competitive retail market enhancements, with tariffs consistent with the order. These riders became effective November 1, 2017;
•
A commitment
to commence a sale process to sell our ownership interests in the Miami Fort, Zimmer and Conesville coal-fired generation plants, with all sales proceeds used to pay debt of DPL and DP&L;
•
Restrictions on DPL making dividend or tax sharing payments and an obligation to convert then existing tax payments owed by DPL to AES into equity investments in DPL. See ; Note 8 – Income Taxes and Note 10 – Equity for more information
on the tax sharing payment restrictions; and
•
Various other riders and competitive retail market enhancements.
On October 19, 2018 IGS, a retail electricity supplier, filed a Notice of Withdrawal from the amended settlement, citing a material modification by the PUCO's October 2017 order. To address the withdrawal, the PUCO established a new procedural schedule, including a hearing currently scheduled to begin April 1, 2019. Additionally, on January
7, 2019, the Ohio Consumers' Counsel appealed the 2017 ESP Order to the Supreme Court of Ohio. That appeal is pending.
DP&L is subject to a SEET threshold and is required to apply general rules for calculating earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings during a given calendar year. The 2017 ESP maintains DP&L’s return on equity SEET threshold at 12% and provides that DMR amounts are excluded from the SEET calculation. On October 22, 2018, a stipulation was reached agreeing that DP&L did not exceed the SEET threshold for 2016 or 2017. That stipulation is pending PUCO approval. In future
years, the SEET could have a material effect on results of operations, financial condition and cash flows.
Impact of Tax Reform
On January 10, 2018 the PUCO initiated a proceeding to consider the impacts of the TCJA to determine the appropriate course of action to pass benefits resulting from the legislation on to ratepayers. The PUCO also directed Ohio utilities to record deferred liabilities for the estimated reduction in federal income tax resulting from the TCJA beginning January 1, 2018. Under the terms of the ESP, DPL will not make tax sharing payments. Under the terms of the stipulation in the distribution rate case mentioned above, DP&L
agreed to file an application at the PUCO by March 1, 2019 to refund eligible excess accumulated deferred income taxes (ADIT) and any related regulatory liability over a 10-year period. Excess ADIT related to depreciation life and method differences will be returned to customers in accordance with federal tax law and related regulations. DP&L’s rates were set using the new tax rate as a result of the distribution rate case.
FERC Proceedings
On May 8, 2018, DP&L filed to adjust its FERC jurisdictional transmission rates to reflect the effects of the decrease in federal income tax rates on the current portion of income tax expense as part of
the TCJA, resulting in a decrease of approximately $2.4 million annually. The revised rates are in effect and all DP&L over and undercollections dating back to the March 21st effective date were settled in December 2018.
On November 15, 2018 FERC issued a Notice of Proposed Rulemaking to address amortization of excess accumulated deferred income taxes resulting from the TCJA and their impact on transmission rates. Such notice requires all public utility transmission providers with stated transmission rates under an Open Access Transmission Tariff (OATT) to determine the amount of excess deferred income taxes caused by the TCJA. DP&L is unable to predict the outcome
of this notice or the impact it may have on our Financial Statements
PJM Transmission Enhancement Settlement
On May 31, 2018, the FERC issued an Order on Contested Settlement regarding the cost allocation method for existing and new transmission facilities contained in the PJM Interconnection’s OATT. The FERC order approved the settlement which reduces DP&L’s transmission costs through PJM beginning in August 2018, including credits
to
reimburse DP&L for amounts overcharged in prior years. DP&L estimates the prior overcharge by PJM to be $41.6 million, of which approximately $14.3 million has been repaid to DP&L through December 31, 2018 and $16.5 million is classified as current in "Accounts receivable, net" and $10.8 million is classified as non-current in "Other deferred assets" on the accompanying Balance Sheet. All of the transmission charges and credits impacted by this FERC order are items
that are included for full recovery in DP&L’s nonbypassable TCRR. Accordingly, DP&L has also established offsetting regulatory liabilities. While this development will have a temporary cash flow benefit to DP&L, there is no impact to operating income or net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018.
Regulatory Assets and Liabilities
In accordance with FASC 980, we have recognized total regulatory assets of $193.7 million and $187.1 million at December
31, 2018 and 2017, respectively, and total regulatory liabilities of $313.2 million and $236.0 million at December 31, 2018 and 2017, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 – Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.
The following table presents
DP&L’s Regulatory assets and liabilities:
Type of Recovery
Amortization Through
December
31,
$ in millions
2018
2017
Regulatory assets, current:
Undercollections
to be collected through rate riders
A/B
2019
$
40.5
$
23.9
Rate case expenses being recovered in base rates
B
2019
0.6
—
Total
regulatory assets, current
41.1
23.9
Regulatory
assets, non-current:
Pension benefits
B
Ongoing
87.5
92.4
Unrecovered
OVEC charges
C
Undetermined
28.7
27.8
Fuel costs
B
2020
3.3
9.3
Regulatory
compliance costs
B
2020
6.1
9.2
Smart grid and AMI costs
B
Undetermined
8.5
7.3
Unamortized
loss on reacquired debt
B
Various
6.0
7.0
Deferred storm costs
A
Undetermined
4.7
2.1
Deferred
vegetation management and other
A/B
Undetermined
7.8
8.1
Total regulatory assets, non-current
152.6
163.2
Total
regulatory assets
$
193.7
$
187.1
Regulatory
liabilities, current:
Overcollection of costs to be refunded through rate riders
A/B
2018
$
34.9
$
14.8
Total
regulatory liabilities, current
34.9
14.8
Regulatory
liabilities, non-current:
Estimated costs of removal - regulated property
Not Applicable
139.1
132.8
Deferred
income taxes payable through rates
Various
116.3
83.4
PJM transmission enhancement settlement
A
2025
16.9
—
Postretirement
benefits
B
Ongoing
6.0
5.0
Total regulatory liabilities, non-current
278.3
221.2
Total
regulatory liabilities
$
313.2
$
236.0
A – Recovery of incurred costs plus
rate of return.
B – Recovery of incurred costs without a rate of return.
C – Recovery not yet determined, but recovery is probable of occurring in future rate proceedings.
Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. DP&L is earning a net return on $5.5 million of this net deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) decoupling rider (see above), (iii) uncollectible rider and (iv) energy efficiency rider. It also includes the current portion of the following deferred costs which are
described in greater detail below: unbilled fuel, regulatory compliance rider costs and deferred storm costs. As current liabilities, this includes overcollection of: (i) competitive bidding energy and auction costs, (ii) energy efficiency program costs, (iii) alternative energy rider, (iv) economic development rider, (v) certain transmission related costs including current portion of PJM transmission enhancement settlement (see above) and (vi) reconciliation rider.
Pension benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” costs of our regulated operations
that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI. As per PUCO and FERC precedents, these costs are probable of future rate recovery.
Unrecovered OVEC charges includes the portion of charges from OVEC that were not recoverable through DP&L’s fuel rider from October 2014 through October 2017. DP&L expects to recover these costs through a future rate proceeding. Beginning
on November 1, 2017, such costs are being recovered through DP&L’s Reconciliation Rider which was authorized as part of the 2017 ESP.
Fuel costs represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L was granted recovery of these costs without a return through the SSO as approved in the 2017 ESP. These costs are being recovered over the three-year period that began November 1, 2017.
Regulatory compliance rider represents
the long-term portion of the regulatory compliance rider which was established by the 2017 ESP to recover the following costs: (i) Consumer Education Campaign, (ii) Retail Settlement System, (iii) Generation Separation, (iv) Bill Format Redesign, (v) Green Pricing Tariff and (vi) Supplier Consolidated Billing. All of these costs except for Generation Separation earn a return. These costs are being recovered over a three-year period.
Rate case costs represents costs associated with preparing a distribution rate case. DP&L was granted recovery of these costs which do not earn a return, as part of the DRO.
Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution
system upgrades and implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. DP&L requested recovery of these costs as part of the December 2018 DMP filing with the PUCO described earlier.
Unamortized
loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the PUCO.
Deferred storm costs represent the long-term portion of deferred costs for major storms which occurred during 2017 and 2018. The 2017 ESP granted DP&L approval to establish a rider by which to seek recovery of these types of costs with a return. DP&L plans to file petitions seeking recovery of each calendar year of storm costs in the following calendar year. Recovery of these costs is probable by 2020, but not certain.
Estimated
costs of removal - regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.
Deferred income taxes payable through rates represent deferred income tax liabilities recognized from the normalization of flow-through items as the result of taxes previously charged to customers. A deferred income tax asset or liability is created from a difference in income recognition between tax laws and accounting methods. As a regulated utility, DP&L includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets. On December
22, 2017, the TCJA was signed, which includes a provision to, among other things, reduce the federal corporate income tax rate to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, DP&L remeasured its deferred income tax assets and liabilities using the new expected tax rate. DP&L believes that the portion of the reduction in the net deferred tax liability which is related to deferred taxes considered in ratemaking will be used in future ratemaking to reduce jurisdictional retail rates. Accordingly, this liability reflects the estimated deferred taxes DP&L expects to return to customers in future periods.
Postretirement benefits represent the qualifying FASC 715 “Compensation – Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.
Note 4 – Property, Plant
and Equipment
The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2018 and 2017:
In
June 2018, DP&L closed on a transmission asset transaction with Duke and AEP, where ownership stakes in certain previously co-owned transmission assets were exchanged to eliminate co-ownership. Each previously co-owned transmission asset became wholly-owned by one of DP&L, Duke or AEP after the transaction. This transaction also resulted in cash proceeds to DP&L of $10.6 million.
AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are
capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. The DP&L AROs are for our retired Hutchings EGU and relate primarily to asbestos removal.
Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.
Primarily
includes settlement related to transfer of Beckjord Facility. See Note 15 – Dispositions for additional information.
See Note 5 – Fair Value for further discussion on ARO fair value measurements.
Asset Removal Costs
We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $139.1 million and $132.8 million in estimated costs of removal at
December 31, 2018 and 2017, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 – Regulatory Matters for additional information.
Changes in the Liability for Transmission and Distribution Asset Removal Costs
The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.
The
table below presents the fair value and cost of our non-derivative instruments at December 31, 2018 and 2017. See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
•
Level 1 (quoted prices in active markets for identical assets or liabilities);
•
Level
2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or
•
Level 3 (unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.
We
did not have any transfers of the fair values of our financial instruments among Level 1, Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 2018 and 2017.
The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented
at the carrying value, net of unamortized premium or discount, in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2020 to 2061.
Master Trust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” was effective as of January 1, 2018. This ASU requires the change in the fair value of equity instruments to be recorded in income rather than in
OCI. Equity Instruments were defined to include all mutual funds, regardless of the underlying investments. Therefore, as of January 1, 2018, AOCI of $1.7 million ($1.1 million net of tax) was reversed to Accumulated Deficit and all future changes to fair value on the Master Trust Assets will be included in income in the period that the changes occur. These changes to fair value were not material for the year ended December 31, 2018. 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 consolidated balance sheets and classified as available for sale.
During
the year ended December 31, 2018, $0.5 million ($0.4 million after tax) of various investments were sold to facilitate the distribution of benefits.
The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DP&L was determined as follows:
Our financial instruments are valued using the market approach in the following categories:
•
Level 1 inputs are used 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 interest rate hedge contracts which are
valued using a benchmark interest rate. Other Level 2 assets include open-ended mutual funds in the Master Trust, which are valued using the end of day NAV per unit.
•
Level 3 inputs such as certain debt balances are considered a Level 3 input because the notes are not publicly traded. Our long-term debt is fair valued for disclosure purposes only.
All of the inputs to the fair value of our derivative instruments are from quoted market prices.
Our long-term debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. As the Wright-Patterson Air Force Base note is not publicly traded, fair value is assumed to equal carrying value. 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 our long-term debt is not recorded at fair value.
Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording
of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. The balance of AROs was $4.7 million and $8.0 million at December 31, 2018 and 2017, respectively.
Note 6 – Derivative Instruments and Hedging Activities
In
the normal course of business, DP&L enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes.
DP&L's
interest rate swaps are designated as a cash flow hedge. At December 31, 2018 and 2017, the principal balance of the interest rate hedges was $140.0 million and $200.0 million, respectively.
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up
to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were considered to determine the hedge effectiveness of the cash flow hedges. With the adoption of ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities effective January 1, 2019, we will no longer be required to calculate effectiveness and thus the entire change in the fair value of a hedging instrument will be recorded in other comprehensive income and amounts deferred will be reclassified to earnings in the same income statement line as the hedged item in the
period in which it settles.
We have two interest rate swaps to hedge the variable interest on our $140.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $140.0 million and will settle monthly based on a one-month LIBOR. As of December 31, 2017, the interest rate swaps had a combined notional amount of $200.0 million. On March 29, 2018, we settled $60.0 million of these interest rate swaps due to the partial repayment of the underlying debt and a gain of $0.8
million was recorded as a reduction to interest expense. Since the swap was partially settled, the remaining swaps were de-designated and then re-designated with a new hypothetical derivative. The AOCI associated with the remaining swaps will be amortized out of AOCI into interest expense over the remaining life of the underlying debt.
We use the income approach to value the swaps, which consists of forecasting future cash flows based on contractual notional amounts and applicable and available market data as of the valuation date. The most common market data inputs used in the income approach include volatilities, spot and forward benchmark interest rates (LIBOR). Forward rates with the same tenor as the derivative instrument being valued are generally obtained from published sources, with these forward rates being assessed quarterly at a portfolio-level
for reasonableness versus comparable published rates. We reclassify gains and losses on the swaps out of AOCI and into earnings in those periods in which hedged interest payments occur.
Beginning accumulated derivative gain / (loss) in AOCI
$
1.4
$
(4.3
)
$
1.6
$
9.2
$
2.0
Net
gains / (losses) associated with current period hedging transactions
(0.1
)
11.9
0.5
15.7
0.4
Net
gains / (losses) reclassified to earnings:
Interest expense
(0.7
)
—
(0.7
)
—
(0.8
)
Loss
from discontinued operations
—
(5.5
)
—
(29.2
)
—
Transfer
of generation assets to subsidiary of parent
—
(2.1
)
—
—
—
Ending
accumulated derivative gain / (loss) in AOCI
$
0.6
$
—
$
1.4
$
(4.3
)
$
1.6
Portion
expected to be reclassified to earnings in the next twelve months
$
0.7
Maximum length of time
that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)
20
Net
gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.
DP&L has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. The fair value derivative position of DP&L's interest rate swaps are as follows:
December
31,
Hedging Designation
Balance sheet classification
2018
2017
Interest rate hedges in a Current asset position
Cash Flow Hedge
Other prepayments and current assets
Gross
Fair Value as presented in the Balance Sheets
$
0.9
$
—
Interest
rate hedges in a non-current asset position
Cash Flow Hedge
Other deferred assets
Gross Fair Value as presented in the Balance Sheets
At December
31, 2018, maturities of long-term debt are summarized as follows:
Due during the years ending December 31,
$ in millions
2019
$
4.6
2020
144.7
2021
4.7
2022
422.8
2023
0.2
Thereafter
16.8
593.8
Unamortized
discounts and premiums, net
(1.4
)
Deferred financing costs, net
(6.3
)
Total long-term debt
$
586.1
Significant Transactions
On January 3, 2018,
DP&L and its lenders amended DP&L's Term Loan B credit agreement. The amendment (a) modified the definition of "applicable rate", from 2.25% per annum to 1.00% per annum - in the case of the Base Rate, and from 3.25% per annum to 2.00% per annum - in the case of the Eurodollar Rate, and (b) included a "call protection" provision which stated that in the event the loan was repriced or any portion of the loans were prepaid, repaid, refinanced, substituted, or replaced on or prior July 3, 2018, such prepayment, acceleration, repayment, refinancing, substitution or replacement would be made at 101%
of the principal amount so prepaid, repaid, refinanced, substituted or replaced. After July 3, 2018 any such transaction would occur at 100% of the principal amount of the then outstanding loans. There were no such transactions prior to July 3, 2018.
On March 30, 2018, DP&L commenced a redemption of $60.0 million of outstanding tax exempt First Mortgage Bonds due 2020 at par value (plus accrued and unpaid interest). These bonds were redeemed at par plus accrued interest on April 30, 2018 with cash on hand.
Debt
Covenants and Restrictions
DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement (financing document entered into in connection with the sale of $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015) have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. DP&L’s Total Debt to Total Capitalization ratio shall not be greater than 0.65 to 1.00; except that, the ratio shall be suspended if DP&L’s
long-term indebtedness is less than or equal to $750.0 million. Additionally, the ratio shall be suspended any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc. As of December 31, 2018, DP&L's ratings meet those requirements and this ratio is suspended for the quarter ended December 31, 2018.
The second financial covenant measures EBITDA to Interest Expense. The Total
Consolidated EBITDA to Consolidated Interest Charges ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreement, is to be not less than 2.50 to 1.00. This covenant was met with a ratio of 8.09 to 1.00 as of December 31, 2018.
DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.
As
of December 31, 2018, DP&L was in compliance with all debt covenants, including the financial covenants described above.
Substantially all property, plant & equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage. All generation assets were released from the lien of DP&L's first and refunding mortgage in connection with the completion of Generation Separation on October 1, 2017.
DP&L’s components of income tax expense on continuing operations were as follows:
Years ended December 31,
$
in millions
2018
2017
2016
Computation of tax expense
Federal
income tax expense (a)
$
22.2
$
31.0
$
50.1
Increases (decreases) in tax resulting from:
State
income taxes, net of federal effect
0.6
0.4
0.4
Depreciation of flow-through differences
(4.3
)
1.2
3.0
Investment
tax credit amortized
(0.3
)
(0.3
)
(0.4
)
Accrual (settlement) for open tax years
—
(0.5
)
3.4
Other,
net (b)
(0.5
)
(0.7
)
(10.5
)
Total tax expense
$
17.7
$
31.1
$
46.0
Components
of tax expense
Federal - current
$
1.4
$
13.5
$
37.7
State
and Local - current
—
0.2
0.5
Total current
1.4
13.7
38.2
Federal
- deferred
15.5
17.0
7.7
State and local - deferred
0.8
0.4
0.1
Total
deferred
16.3
17.4
7.8
Total tax expense
$
17.7
$
31.1
$
46.0
(a)
The
statutory tax rate of 21% in 2018 and 35% in 2017 and 2016 was applied to pre-tax earnings.
(b)
Includes expense / (benefit) of $(0.7) million and $(0.4) million in the years ended December 31, 2017 and 2016, respectively,
of income tax related to adjustments from prior years.
Effective and Statutory Rate Reconciliation
The following table summarizes a reconciliation of the U.S. statutory federal income tax rate to DP&L's effective tax rate, as a percentage of income from continuing operations before taxes for the years ended December 31, 2018, 2017 and 2016:
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
On
December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law.
In 2017, we recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) which provides SEC guidance on the application of FASC 740, Income Taxes, in the reporting period in which the TCJA was signed into law. Accordingly, our 2017 financial statements reflected the income tax effects of U.S. tax reform for which the accounting was complete and provisional amounts for those impacts for which the accounting under FASC 740 was incomplete, but a reasonable estimate could be determined.
We completed our calculation of the impact of the TCJA in our income tax provision for the year
ended December 31, 2018 in accordance with our understanding of the TCJA and guidance available as of the date of this filing. As a result of this remeasurement, certain deferred tax assets and liabilities related to regulated utility property of $17.0 million and $135.2 million at December 31, 2018 and 2017 were recorded as regulatory liabilities and were non-cash adjustments. These amounts result from the remeasurement of certain deferred tax assets and liabilities as the rates changed from 35% to 21%. Additionally, consistent with the provisions of SAB 118, in 2018 we finalized the remeasurement of deferred tax asset
balances transferred to AES Ohio Generation as part of Generation Separation which resulted in an additional $10.0 million return of capital to DPL in 2018.
The following table presents the tax expense / (benefit) related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.
Years
ended December 31,
$ in millions
2018
2017
2016
Tax expense / (benefit)
$
(0.3
)
$
4.0
$
(7.0
)
Uncertain
Tax Positions
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows:
Of the December
31, 2018 balance of unrecognized tax benefits, $4.8 million is due to uncertainty in the timing of deductibility.
We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued and tax expense / (benefit) recorded were not material for each period presented.
Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal – 2011 and forward
State and Local – 2011 and forward
None of the unrecognized tax benefits are expected to significantly increase or decrease
within the next twelve months other than those subject to expiring statute of limitations.
Note 9 – Benefit Plans
Defined Contribution Plans
DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.
Certain non-union and union employees become eligible to participate in their respective plan upon date of hire.
Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,400 for 2018 and they are fully vested in their employer contributions after 3
years of service. All participants are fully vested in their own contributions.
We contributed $3.7 million, $3.1 million and $5.1 million for the years ended December 31, 2018, 2017 and 2016, respectively. DP&L matching contributions are paid quarterly, in arrears. Therefore, the contributions by year include the fourth quarter matching contribution that is paid in the following year. DP&L also contributes an annual bonus to the accounts of its union participants. This payment is typically made in January of the following year.
Defined
Benefit Plans
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan formula was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s
death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan. In addition, employees that transferred from DP&L to AES Ohio Generation due to Generation Separation maintain their previous eligibility to participate in the DP&L pension plan.
Almost all management employees beginning employment on or after January
1, 2011 participate in a cash balance pension plan formula. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.
In
addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners in our co-owned generating plants related to our share of their pension liabilities within Pension, retiree and other benefits on our Balance Sheets.
We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent
the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.
Postretirement Benefits
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded
a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust. These postretirement health care benefits and the related unfunded obligation of $9.2 million and $12.7 million at December 31, 2018 and 2017, respectively, were not material to the financial statements in the periods covered by this report.
The
following tables set forth the changes in our pension plan's obligations and assets recorded on the Balance Sheets at December 31, 2018 and 2017. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate and have not been adjusted for $1.8 million and $1.1 million of costs billed to the Service Company for the years ended December 31, 2018 and 2017
or $3.3 million and $0.7 million of costs billed to AES Ohio Generation for the years ended December 31, 2018 and 2017.
$ in millions
Years ended December 31,
Change
in benefit obligation
2018
2017
Benefit obligation at January 1
$
436.9
$
419.6
Service
cost
6.1
5.7
Interest cost
13.8
14.2
Plan
amendments
5.1
—
Plan curtailment
—
3.0
Actuarial
(gain) / loss
(34.6
)
28.1
Benefits paid
(40.8
)
(33.7
)
Benefit
obligation at December 31
386.5
436.9
Change in plan assets
Fair
value of plan assets at January 1
357.5
341.0
Actual return on plan assets
(11.7
)
44.8
Employer
contributions
7.9
5.4
Benefits paid
(40.8
)
(33.7
)
Fair
value of plan assets at December 31
312.9
357.5
Unfunded status of plan
$
(73.6
)
$
(79.4
)
December
31,
Amounts recognized in the Balance sheets
2018
2017
Current liabilities
$
(0.4
)
$
(0.4
)
Non-current
liabilities
(73.2
)
(79.0
)
Net liability at end of year
$
(73.6
)
$
(79.4
)
Amounts
recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost
$
10.4
$
6.7
Net
actuarial loss
137.2
148.3
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
$
147.6
$
155.0
Recorded
as:
Regulatory asset
$
87.3
$
92.2
Accumulated
other comprehensive income
60.3
62.8
Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
$
147.6
$
155.0
The
accumulated benefit obligation for our defined benefit pension plans was $378.7 million and $428.3 million at December 31, 2018 and 2017, respectively.
The net periodic benefit cost of the pension plans was:
Years
ended December 31,
$ in millions
2018
2017
2016
Service cost
$
6.1
$
5.7
$
5.7
Interest
cost
13.8
14.2
14.7
Expected return on assets
(21.2
)
(22.8
)
(22.8
)
Plan
curtailment (a)
—
5.6
5.7
Amortization of unrecognized:
Actuarial
loss
9.4
8.7
7.2
Prior service cost
1.4
1.5
3.0
Net
periodic benefit cost
$
9.5
$
12.9
$
13.5
Rates
relevant to each year's expense calculations
Discount rate
3.66
%
4.28
%
4.49
%
Expected
return on plan assets
6.25
%
6.50
%
6.50
%
(a)
As a result of the decision to retire certain coal-fired plants, we recognized
a plan curtailment of $5.6 million and $5.7 million in 2017 and 2016, respectively.
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Years
ended December 31,
$ in millions
2018
2017
2016
Net actuarial loss
$
3.4
$
9.1
$
20.9
Plan
curtailment (a)
—
(5.6
)
(5.7
)
Reversal of amortization item:
Net
actuarial loss
(9.4
)
(8.7
)
(7.2
)
Prior service cost
(1.4
)
(1.5
)
(3.0
)
Total
recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
$
(7.4
)
$
(6.7
)
$
5.0
Total
recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
$
2.1
$
6.2
$
18.5
(a)
As
a result of the decision to retire certain coal-fired plants, we recognized a plan curtailment of $5.6 million and $5.7 million in 2017 and 2016, respectively.
Significant Gains and Losses Related to Changes in the Benefit Obligation
The actuarial gain of $34.6 million decreased the benefit obligation for the year ended December 31, 2018 and an actuarial loss of $28.1 million increased the benefit obligation for the year ended December
31, 2017. The actuarial gain in 2018 was primarily due to an increase in the discount rate, while the actuarial loss in 2017 was primarily due to a decrease in the discount rate.
Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
At
December 31, 2018, we are maintaining our long-term rate of return assumption of 6.25% for pension plan assets. The rate of return represents our long-term assumptions based on our long-term portfolio mix. Also, at December 31, 2018, we have increased our assumed discount rate to 4.35% from 3.66% for pension expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in 2019 pension expense of approximately
$3.2 million. A one percent decrease in the rate of return assumption for pension would result in an increase in 2019 pension expense of approximately $3.2 million. A 25-basis point increase in the discount rate for pension would result in a decrease of approximately $0.1 million to 2019 pension expense. A 25-basis point decrease in the discount rate for pension would result in an increase of approximately $0.4 million to 2019 pension expense.
In
determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2018. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.
In future periods, differences in the actual
return on pension plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any, to the plans.
The weighted average assumptions used to determine benefit obligations at December 31, 2018, 2017 and 2016 were:
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income
investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.
Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations consider the plan’s long-term objectives. The long-term target allocations for plan assets are 24% – 52% for equity securities and 47% – 65% for fixed income securities. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and
emerging market debt funds.
Tactically, the committees, on a short-term basis, will make asset allocations that are outside the long-term allocation guidelines. The short-term allocation positions are likely to not exceed one-year in duration. In addition to the equity and fixed income investments, the short-term allocation may also include a relatively small allocation to alternative investments. The plan currently has a small target allocation in a core property fund.
Most of our plan assets are measured using quoted, observable prices which are considered Level One inputs in the Fair Value Hierarchy. The Core Property Collective Fund is measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.
The
following table summarizes our target pension plan allocation for 2018:
Long-Term Mid-Point Target Allocation
Percentage of plan assets as of December 31,
Asset category
2018
2017
Equity
Securities
38%
33%
35%
Debt Securities
56%
58%
55%
Cash and
Cash Equivalents
—%
1%
—%
Real Estate
6%
8%
10%
The
fair values of our pension plan assets at December 31, 2018 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2018
Quoted prices in active markets for identical assets
Significant observable inputs
Significant unobservable inputs
Asset category
(Level
1)
(Level 2)
(Level 3)
Mutual funds:
U.S.
equities (a)
$
79.3
$
79.3
$
—
$
—
International
equities (a)
25.9
25.9
—
—
Fixed
income (b)
143.7
143.7
—
—
Fixed
income securities:
U.S. Treasury securities
37.5
37.5
—
—
Cash
and cash equivalents:
Money market funds (c)
2.4
2.4
—
—
Other
investments:
Core property collective fund (d)
24.1
—
24.1
—
Total
pension plan assets
$
312.9
$
288.8
$
24.1
$
—
(a)
This
category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
This category is comprised of investments in U.S. treasury obligations that seek to preserve principal and maintain liquidity while providing current income. The funds are valued at the assets’ amortized cost to maintain a stable per share net asset value.
(d)
This category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value
the fund.
The fair values of our pension plan assets at December 31, 2017 by asset category are as follows:
Fair Value Measurements for Pension Plan Assets at December 31, 2017
Quoted prices in active markets for identical assets
Significant observable inputs
Significant unobservable inputs
Asset category
(Level
1)
(Level 2)
(Level 3)
Mutual funds:
U.S.
equities (a)
$
78.2
$
78.2
$
—
$
—
International
equities (a)
46.3
46.3
—
—
Fixed
income (b)
163.3
163.3
—
—
Fixed
income securities:
U.S. Treasury securities
33.5
33.5
—
—
Other
investments: (c)
Core property collective fund
36.2
—
36.2
—
Total
pension plan assets
$
357.5
$
321.3
$
36.2
$
—
(a)
This
category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This
category represents a property fund that invests in commercial real estate. The fair value of the fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
Pension Funding
We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $7.5 million to the pension plan in the year ended December 31, 2018 and $5.0 million to the pension plan in each of the years ended December 31, 2017 and 2016.
We
expect to make contributions of $0.4 million to our SERP in 2019 to cover benefit payments. We also expect to make contributions of $7.5 million to our pension plan during 2019.
Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that consider the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.
From an ERISA funding perspective, DP&L’s
funded target liability percentage was estimated to be 101%. In addition, DP&L must also contribute the normal service cost earned by active participants during the plan year. The funding of normal cost is expected to be approximately $5.4 million in 2019, which includes $1.9 million for plan expenses. Each year thereafter, if the plan’s underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. DP&L’s funding policy for the pension plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for
federal income tax purposes.
Benefit payments, which reflect future service, are expected to be paid as follows:
On
October 13, 2016 (the "Redemption Date"), DP&L redeemed all of its issued and outstanding preferred stock, consisting of the following series: Preferred Stock, 3.75% Series A, Cumulative (the “Series A Stock”); Preferred Stock, 3.75% Series B, Cumulative (the “Series B Stock”); and Preferred Stock, 3.90% Series C, Cumulative (the “Series C Stock” and, together with the Series A Stock and the Series B Stock, the “Preferred Stock”). On the Redemption Date, the Preferred Stock of each series was redeemed at the following prices as specified in DP&L’s Amended and Restated Articles of Incorporation, plus, in each case an amount equal to all accrued dividends
payable with respect to such Preferred Stock to the Redemption Date: a price of $102.50 per share for the Series A Stock, a price of $103.00 per share for the Series B Stock, and a price of $101.00 per share for the Series C Stock. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of DP&L, except the right to payment of the redemption price, ceased to exist. The difference between the carrying value of the Redeemable Preferred Stock and the redemption amount was charged to Other paid-in capital.
Common Stock
DP&L
has 50,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2018. All common shares are held by DP&L’s parent, DPL.
Equity Settlement of Related Party Payable
In 2016, DP&L settled a $7.5 million payable to DPL relating to income taxes. This payable balance was settled through equity and DPL's investment in DP&L
was increased by $7.5 million as consideration for extinguishing the payable.
Capital Contribution and Returns of Capital
In 2018, DP&L received an $80.0 million capital contribution from its parent, DPL. In addition, DP&L made returns of capital payments of $43.8 million to DPL. In addition, DP&L recorded $10.0 million in 2018 as a return of capital to transfer additional deferred tax amounts under Generation Separation.
See Note 8 – Income Taxes and Note 14 – Generation Separation for more information.
In 2017, DP&L received a $70.0 million capital contribution from its parent, DPL. In addition, DP&L made returns of capital payments of $39.0 million to DPL. In connection with Generation Separation, DP&L recorded $86.2 million as a return of capital. See Note 14 – Generation Separation
for more information.
In 2016, DP&L made a dividend payment of $70.0 million to DPL.
Note 11 – Contractual Obligations, Commercial Commitments and Contingencies
DP&L – Equity Ownership Interest
DP&L has a 4.9% equity ownership interest in OVEC which is recorded using the cost method of accounting
under GAAP. At December 31, 2018, DP&L could be responsible for the repayment of 4.9%, or $68.1 million, of a $1,389.6 million debt obligation comprised of both fixed and variable rate securities with maturities between 2019 and 2040. OVEC could also seek additional contributions from us to avoid a default in the event that other OVEC members defaulted on their respective OVEC obligations. One of the other OVEC members, with a 4.85% interest in OVEC, filed for bankruptcy protection and the bankruptcy court approved that member's rejection of the OVEC arrangement
and its related obligations on July 31, 2018. We do not expect these events to have a material impact on our financial condition, results of operations or cash flows.
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2018, these include:
Payments
due in:
$ in millions
Total
Less than 1 year
2 - 3 years
4 - 5 years
More than 5 years
Electricity purchase commitments
$
209.4
$
139.5
$
69.9
$
—
$
—
Purchase
orders and other contractual obligations
$
39.8
$
11.3
$
14.7
$
13.8
$
—
Electricity
purchase commitments:
DP&L enters into long-term contracts for the purchase of electricity. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.
Purchase orders and other contractual obligations:
At December 31, 2018, DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and DP&L's ability
to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above
Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Financial Statements. As such, costs, if any,
that may be incurred in excess of those amounts provided as of December 31, 2018, cannot be reasonably determined.
Environmental Matters
DP&L's facilities and operations are subject to a wide range of federal, state and local environmental laws, rules and regulations. The environmental issues that may affect us include the following. However, as described further below, as a result of DPL’s retirement of its Stuart and Killen generating stations, the sale of its ownership interest in the Miami Fort and Zimmer generating stations, the planned 2020 retirement of Conesville and our exiting of our generation business, certain
of these environmental regulations and laws are now not expected to have a material impact on DPL with respect to these generating stations.
•
The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions;
•
Rules and future rules issued by the USEPA, the Ohio EPA or other authorities that require or will require reporting and reductions of GHGs;
•
Rules
and future rules issued by the USEPA, the Ohio EPA or other authorities associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits; and
•
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste.
In addition to imposing continuing compliance obligations, these laws, rules 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 laws, rules and regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have immaterial accruals for loss contingencies for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable, or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.
We have several pending environmental matters associated with our current and previously owned and operated coal-fired generation units. Some of these matters could have material adverse impacts on our results of operations, financial condition or cash flows.
Note 12 – Related Party Transactions
Service Company
The Service Company allocates the costs for services provided based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L,
are not subsidizing costs incurred for the benefit of other businesses.
Benefit Plans
DPL participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments.
Long-term Compensation Plan
During 2018, 2017 and 2016,
many of DP&L’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2018, 2017 and 2016 was $0.3 million, $0.4 million and $0.5 million,
respectively, and was included in “Other Operating Expenses” on DP&L’s Statements of Operations. The value of these benefits is being recognized over the 36-month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on DP&L’s Balance Sheets in accordance with FASC 718 “Compensation - Stock Compensation.”
The following table provides a summary of our related party transactions:
Years
ended December 31,
$ in millions
2018
2017
2016
DP&L Cost of revenues:
Fuel
and power purchased from AES Ohio Generation
$
—
$
5.4
$
8.7
DP&L Operation & Maintenance
Expenses:
Premiums charged for insurance services
provided by MVIC (a)
$
2.7
$
3.1
$
3.4
Transactions
with the Service Company:
Charges for services provided
$
25.7
$
39.0
$
38.7
Charges
to the Service Company
$
4.9
$
4.2
$
4.5
Transactions with other AES affiliates:
Charges
for health, welfare and benefit plans
$
8.7
$
14.3
$
9.4
Charges to affiliates for non-power goods or services (b)
Net
receivable from / (payable) to other AES affiliates
$
(0.5
)
$
4.8
(a)
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 charged by MVIC to DP&L.
(b)
In the normal course of business DP&L incurred and recorded expenses on behalf of DPL affiliates. Such expenses included but were not limited to employee-related
expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charged these expenses to the affiliates at DP&L’s cost and credited the expense in which they were initially recorded.
Income Taxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L. Under a tax sharing agreement with DPL, DP&L is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate
return method. Under this agreement, DP&L had a net receivable balance of $19.6 million and $6.5 million at December 31, 2018 and 2017, respectively, which is
recorded in Taxes receivable on the accompanying Balance Sheets. During 2018, 2017 and 2016, DP&L made net payments of
$14.6 million, $28.1 million and $0.0 million respectively, to DPL for its share of income taxes.
Note 13 – Revenue
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue
is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Retail Revenues – DP&L energy sales to utility customers are based on the reading of meters at the customer's location that occurs on a systematic basis throughout the month. DP&L sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Performance obligations for retail revenues are satisfied over time as energy is delivered and the same method is used to measure progress, and thus the performance obligation meets the criteria to be considered a series. This includes both the promise to transfer energy and other distribution and/or transmission services.
In
exchange for the exclusive right to sell or distribute electricity in our service area, DP&L is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that DP&L is allowed to charge customers for electricity. Since tariffs are approved by the regulator, the price that DP&L has the right to bill corresponds directly with the value to the customer of DP&L's performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff.
In cases where a customer chooses to receive generation services from a CRES
provider, the price for generation services is negotiated between the customer and the CRES provider, and DP&L only serves as a billing agent if requested by the CRES provider. As such, DP&L recognizes the consolidated billing arrangement with the CRES provider on a net basis, thereby recording no revenue for the generation component. Retail revenue from these customers would only be related to transmission and distribution charges.
Wholesale Revenues – DP&L's share of the power produced at OVEC is sold to PJM and is classified as Wholesale revenues.
In PJM, the promise to
sell energy as wholesale revenue is separately identifiable from participation in the capacity market and the two products can be transacted independently of one another. Therefore, wholesale revenues are a separate contract with a single performance obligation. Revenue is recorded based on the quantities (MWh) delivered in each hour during each month at the spot price, making the contract effectively “month-to-month”.
RTO Revenues – Compensation for use of DP&L’s transmission assets and compensation for various ancillary services are classified as RTO revenues. As DP&L owns and operates transmission lines in southwest Ohio within PJM, demand charges collected from network customers by PJM are then allocated to the appropriate transmission owners (i.e.
DP&L) and recognized as transmission revenues. Additionally, as an owner of generation and transmission assets within PJM, DPL is compensated for various ancillary services; such as reactive supply, regulation services, scheduling reserves, operating reserves, spinning/synchronized reserves as well as congestion credits that are provided to PJM via these assets.
Transmission revenues have a single performance obligation, as transmission services represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The price that DP&L, as the transmission operator, has the right to bill (received
as a credit from PJM) corresponds directly with the value to the customer of performance completed in each period, as the price paid is the allocation of the tariff rate (as approved by the regulator) charged to network participants.
RTO Capacity Revenues – Compensation received from PJM for making installed generation capacity available to satisfy system integrity and reliability requirements is classified as RTO capacity revenues. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. If plant availability exceeds a contractual target, we may receive a performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a non-availability penalty. Such bonuses or penalties represent a form of
variable consideration and are estimated and recognized when it is probable that there will not be a significant reversal and therefore the transaction price is recognized on an output basis based on the MWs.
RTO capacity revenues have a single performance obligation, as capacity is a distinct good. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. The capacity price is set through a competitive auction process established by PJM.
DP&L's revenue from contracts with customers was $706.6 million for the
year ended December 31, 2018. The following table presents our revenue from contracts with customers and other revenue by segment for the year ended December 31, 2018:
Year ended December 31,
$ in millions
2018
Retail
Revenue
Retail revenue from contracts with customers
$
625.8
Other retail revenues (a)
32.1
Wholesale Revenue
Wholesale
revenue from contracts with customers
29.9
RTO revenue
43.1
RTO capacity revenues
7.8
Total revenues
$
738.7
(a)
Other
retail revenue primarily includes alternative revenue programs not accounted for under FASC 606.
The balances of receivables from contracts with customers were $70.1 million and $62.1 million as of December 31, 2018 and January 1, 2018, respectively. Payment terms for all receivables from contracts with customers are typically within 30 days.
We have elected to apply the optional disclosure exemptions under FASC 606. Therefore, we have no disclosures pertaining to revenue expected to be recognized in any future year
related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled for DP&L.
Note 14 – Generation Separation
On October 1, 2017, DP&L
completed the transfer of its generating plants, the real property on which the generation plants and generation-related assets are sited, step-up transformers and other transmission plant assets used to interconnect with the electric transmission grid, fuel inventory, equipment inventory and spare parts, working capital, and other miscellaneous generation-related assets and liabilities to AES Ohio Generation. The transfer was completed as a contribution through an asset contribution agreement to a wholly-owned subsidiary of DP&L after which DP&L then distributed all of the outstanding equity in the subsidiary to DPL and then the subsidiary was merged into AES Ohio Generation.
Long-term debt that transferred to AES Ohio Generation relates to capital leases.
(b)
Accrued taxes and deferred taxes transferred to AES Ohio
Generation represent the tax asset position netted with liabilities on DP&L prior to Generation Separation.
DP&L's generation business met the criteria to be classified as a discontinued operation, and, accordingly, the historical activity has been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2017 and 2016.
The following table summarizes the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated:
Years
ended December 31,
$ in millions
2017
2016
Revenues
$
358.4
$
557.9
Cost
of revenues
(191.6
)
(341.1
)
Operating and other expenses
(156.8
)
(202.0
)
Fixed-asset
impairment
(66.3
)
(1,353.5
)
Loss from discontinued operations
(56.3
)
(1,338.7
)
Income
tax benefit from discontinued operations
(15.9
)
(468.4
)
Net loss from discontinued operations
$
(40.4
)
$
(870.3
)
In
2018, DP&L transferred additional deferred taxes to AES Ohio Generation under the provisions of SAB 118 through an equity transaction with DPL in the amount of $10.0 million. See Note 8 – Income Taxes for additional information.
Cash flows related to discontinued operations are included in the Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $21.8 million and $29.9 million for the years ended December 31, 2017 and 2016, respectively. Cash
flows from investing activities for discontinued operations were $(3.5) million and $(39.0) million for the years ended December 31, 2017 and 2016, respectively.
The PUCO authorized DP&L to maintain long-term debt of $750 million or 75% of its rate base, whichever is greater, until January 1, 2018, or to file an application to explain why it would not achieve those metrics. Accordingly, $750.0 million of debt and the pro rata interest expense associated with
that debt were allocated to continuing operations. All remaining interest expense is included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million and $0.5 million for the years ended December 31, 2017 and 2016, respectively.
Beckjord
Facility – On February 26, 2018, DP&L and its co-owners of the retired Beckjord Facility agreed to transfer their interests in the retired Facility to a third party, including their obligations to remediate the Facility and its site, and the transfer occurred on that same date. As a result, DP&L recognized a loss on the transfer of $12.4 million and made cash expenditures of $14.5 million, inclusive of cash expenditures for the transfer charges. The Beckjord Facility was retired in 2014, and, as such, the income / (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December
31, 2018, 2017 and 2016, excluding the loss on transfer noted above.
Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A – Controls and Procedures
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.
We carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e)
and 15d-15(e)). Based upon this evaluation, our CEO and CFO concluded that as of December 31, 2018, our disclosure controls and procedures were effective.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•
pertain
to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
•
provide reasonable assurance that unauthorized acquisition, use or disposition of our assets that could have a
material effect on the financial statements are prevented or detected timely.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management
assessed the effectiveness of our internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in 2013. Based on this assessment, management believes that we maintained effective internal control over financial reporting as of December 31, 2018.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2018
that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item
10 – Directors, Executive Officers and Corporate Governance
Not applicable pursuant to General Instruction I of the Form 10-K.
Item 11 – Executive Compensation
Not applicable pursuant to General Instruction I of the Form 10-K.
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Not applicable pursuant to General Instruction I of the Form 10-K.
Item
13 – Certain Relationships and Related Transactions, and Director Independence
Not applicable pursuant to General Instruction I of the Form 10-K.
Item 14 – Principal Accountant Fees and Services
Accountant Fees and Services
The following table presents the aggregate fees billed for professional services rendered to DPL and DP&L by Ernst & Young LLP during the years ended December 31, 2018 and 2017.
Other than as set forth below, no professional services were rendered or fees billed by Ernst & Young LLP during the years ended December 31, 2018 and 2017.
Audit
fees relate to professional services rendered for the audit of our annual financial statements and the reviews of our quarterly financial statements and other services that are normally provided in connection with regulatory filing or engagements and services rendered under an agreed upon procedure engagement related to environmental studies.
(b)
Audit-related fees relate to services rendered to us for assurance and related services.
The Boards of Directors of DPL Inc. and The Dayton Power and Light Company (collectively, the Board) pre-approve all audit and permitted non-audit services, including engagement fees and terms for such services
in accordance with Section 10A of the Securities Exchange Act of 1934, as amended. The Board will generally pre-approve a listing of specific services and categories of services, including audit, audit-related and other services, for the upcoming or current fiscal year, subject to a specified cost level. Any material service not included in the pre-approved list of services must be separately pre-approved by the Board. In addition, all audit and permissible non-audit services in excess of the pre-approved cost level, whether or not such services are included on the pre-approved list of services, must be separately pre-approved by the Board.
Asset Purchase Agreement, dated as of December 15, 2017, by and among AES Ohio Generation, LLC, DPL Inc., Kimura Power, LLC, and Rockland Power Partners III, LP
Composite
Indenture dated as of October 1, 1935, between The Dayton Power and Light Company and Irving Trust Company, Trustee with all amendments through the Twenty-Ninth Supplemental Indenture
Amended
and Restated Trust Agreement dated as of August 31, 2001 among DPL Inc., The Bank of New York, The Bank of New York (Delaware), the administrative trustees named therein, and several Holders as defined therein
Loan Agreement dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series A bonds
Loan
Agreement dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series B bonds
Bond Purchase and Covenants Agreement dated as of August 1, 2015, among The Dayton Power and Light Company, SunTrust Bank, as Administrative Agent, and the several lenders from time to time party thereto
Amendment
dated February 21, 2017 to Bond Purchase and Covenants Agreement by and among The Dayton Power and Light Company, SunTrust Bank, as Administrative Agent, and several lenders from time to time party thereto, dated as of August 1, 2015
Credit Agreement dated as of July 31, 2015, among DPL Inc., U.S. Bank National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and an L/C Issuer, PNC Bank, National Association, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement
First Amendment dated as of December 15, 2017, to Credit Agreement by and among DPL Inc., U.S. Bank National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and an L/C Issuer, PNC Bank, National Association, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement, dated as of July 31, 2015
Open-end Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing, dated as of July 31, 2015, made by DPL Energy LLC to U.S. Bank National Association, as Collateral Agent and Mortgagee
Credit Agreement dated as of July 31, 2015, among The Dayton Power and Light Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Fifth Third Bank, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement
Amendment dated as of February 21, 2017 to Credit Agreement by and among The Dayton Power and Light Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Fifth Third Bank, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement, dated as of July 31, 2015
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, 2015
First
Modification to Open-End Leasehold Mortgage, Security Agreement, Assignment of Leases and Rents, and Fixture Filing between AES Ohio Generation, LLC and U.S. Bank National Association, dated as of October 1, 2017
Credit
Agreement dated August 24, 2016, among The Dayton Power and Light Company, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent and collateral agent, Morgan Stanley Senior Funding, Inc., as a lender and BMO Capital Markets Corp., Fifth Third Securities, The Huntington National Bank, PNC Capital Markets LLC, RBC Capital Markets, LLC, Regions Capital Markets, a division of Regions Bank, and SunTrust Robinson Humphrey, Inc., as managing agents
Amendment
to Credit Agreement dated as of January 3, 2018, among The Dayton Power and Light Company, JPMorgan Chase Bank, N.A., as Administrative Agent and certain of the lenders party thereto
Pledge and Security Agreement dated as of August 24, 2016, between The Dayton Power and Light Company and JPMorgan Chase Bank, N.A., as
collateral agent
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification
of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, we may not file as an exhibit to this Form 10-K certain instruments with respect to long-term debt if the total amount of securities authorized
thereunder does not exceed 10% of the total assets of us and our subsidiaries on a consolidated basis, but we hereby agree to furnish to the SEC on request any such instruments.
Item 16 – Form 10-K Summary
None.
144
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company have duly caused this report to be signed
on their behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of DPL Inc. and in the capacities and on the dates indicated.
Pursuant to the requirements
of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of The Dayton Power and Light Company and in the capacities and on the dates indicated.
(a) Amounts
written off, net of recoveries of accounts previously written off
(b)
Balances and activity for valuation allowances for deferred tax assets includes that of amounts presented within both the "Deferred taxes" line and the "Non-current liabilities of discontinued operations and held-for-sale businesses" line on DPL’s Consolidated Balance Sheets.
