UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(x) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172018
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
|
| | | | |
Commission
File Number | | Registrant, State of Incorporation, |
DPL INC. Address and Telephone Number(an Ohio corporation)
| |
THE DAYTON POWER AND LIGHT COMPANY
I.R.S. Employer (an Ohio corporation)
Identification No.
|
| Commission file number 1-9052 | | Commission file number 1-2385 |
| | | | | |
1-9052 | | DPL INC. | | 31-1163136 |
| | (An1065 Woodman Drive Dayton, Ohio Corporation) | | |
| 45432 | | 1065 Woodman Drive
Dayton, Ohio 45432 | | |
| | 937-259-7215 | | 937-259-7215 |
| | | | | |
1-2385I.R.S. Employer Identification No. 31-1163136 | | THE DAYTON POWER AND LIGHT COMPANY | | I.R.S. Employer Identification No. 31-0258470 |
| | (An Ohio Corporation) | | |
| | 1065 Woodman Drive
Dayton, Ohio 45432 | | |
| | 937-259-7215 | | |
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
|
| | |
| DPL Inc. | Yes o | No x |
| The Dayton Power and Light Company | Yes o | No x |
Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
|
| | |
| DPL Inc. | Yes 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 |
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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
|
| | |
| DPL Inc. | Yes x | No o |
| The Dayton Power and Light Company | Yes x | No o |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K 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.
At December 31, 2017,2018, each registrant had the following shares of common stock outstanding:
|
| | | | |
| Registrant | | Description | | Shares Outstanding |
| | | | | |
| DPL Inc. | | Common Stock, no par value | | 1 |
| | | | | |
| The Dayton Power and Light Company | | Common Stock, $0.01 par value | | 41,172,173 |
Documents incorporated by reference: None
This combined Form 10-K 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.
DPL Inc. and The Dayton Power and Light Company
Table of Contents
- Annual Report on Form 10-K
Fiscal Year Ended December 31, 20172018
|
| |
| Page No. |
| Glossary of Terms | |
| Part I | |
| |
| |
| |
| |
| |
| |
| Part II | |
| |
| |
| |
| |
| | |
| |
| Consolidated Statements of Operations | |
| Consolidated Statements of Comprehensive Income / (Loss) | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Shareholder's Equity | |
| Notes to Consolidated Financial Statements | |
| Note 1 – Overview and Summary of Significant Accounting Policies | |
| Note 2 – Supplemental Financial Information | |
| Note 3 – Regulatory Matters | |
| Note 4 – Property, Plant and Equipment | |
| Note 5 – Fair Value | |
| Note 6 – Derivative Instruments and Hedging Activities | |
| Note 7 – Long-term debt | |
| Note 8 – Income Taxes | |
| Note 9 – Benefit Plans | |
| Note 10 – Equity | |
| Note 11 – Contractual Obligations, Commercial Commitments and Contingencies | |
| Note 12 – Related Party Transactions | |
| Note 13 – Business Segments | |
| Note 14 – Revenue | |
| Note 15 – Discontinued Operations | |
| Note 16 – Dispositions | |
| Note 17 – Fixed-asset impairments | |
| |
| Statements of Operations | |
| Statements of Comprehensive Income / (Loss) | |
| Balance Sheets | |
| Statements of Cash Flows | |
| Statements of Shareholder's Equity | |
| Notes to Financial Statements | |
| Note 1 – Overview and Summary of Significant Accounting Policies | |
| Note 2 – Supplemental Financial Information | |
| Note 3 – Regulatory Matters | |
| Note 4 – Property, Plant and Equipment | |
| Note 5 – Fair Value | |
| Note 6 – Derivative Instruments and Hedging Activities | |
| Note 7 – Long-term debt | |
| Note 8 – Income Taxes | |
| Note 9 – Benefit Plans | |
| Note 10 – Equity | |
| Note 11 – Contractual Obligations, Commercial Commitments and Contingencies | |
| Note 12 – Related Party Transactions | |
| Note 13 – Revenue | |
| Note 14 – Generation Separation | |
| Note 15 – Dispositions | |
| Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |
| |
| |
| Part III | |
| |
| |
| |
| |
| |
| Part IV | |
| |
| |
| |
| |
GLOSSARY OF TERMS
The following select terms, abbreviations or acronyms are used in this Form 10-K:
|
| |
Abbreviation or AcronymTerm | Definition |
| 2017 ESP | DP&L's ESP, approved October 20, 2017, effective November 1, 2017 |
| AEP Generation | 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 facilitiesfacility 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 located in the “rest of” RTO area of PJM. |
| CCR | Coal Combustion Residuals, which consists of bottom ash, fly ash, and air pollution |
CO2
Conesville | Carbon Dioxide |
CP | The Capacity Performance "CP" program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours.” The AES Ohio Generation units operate underGeneration's interest in Unit 4 at the CP construct starting June 1, 2016.Conesville EGU which is operated by AEP |
| CPP | The Clean Power Plan, the USEPA's final CO2carbon 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 |
D.C. Circuit Court | United States Court of Appeals for the District of Columbia Circuit |
| 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, including sales by a wholly-owned subsidiary, MC Squared, which DPLER sold on April 1, 2015.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 |
|
| |
GLOSSARY OF TERMS (cont.) |
Abbreviation or Acronym | Definition |
DMR | Distribution modernization rider - designed to allow DP&L to modernize and/or maintain its transmission and distribution infrastructure. |
| 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 unitGenerating 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 |
ESP 1 | ESP approved by PUCO order dated June 24, 2009 |
ESP 2 | ESP approved by PUCO order dated September 4, 2013. The Ohio Supreme Court ruled that it was invalid. DP&L withdrew its ESP 2 on July 27, 2016 and reinstated previously authorized rates from ESP 1 |
| FASB | Financial Accounting Standards Board |
| FASC | FASB Accounting Standards Codification |
| FERC | Federal Energy Regulatory Commission |
FGD | Flue Gas Desulfurization |
| 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 |
|
| |
| 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 |
ISO | Independent System Operator |
| 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 |
MC Squared | MC Squared Energy Services, LLC, a retail electricity supplier formerly wholly-owned by DPLER, sold on April 1, 2015 |
| Merger | The merger of DPL and Dolphin Sub, Inc., a wholly-owned subsidiary of AES. On November 28, 2011, DPL became a wholly-owned subsidiary of AES. |
Merger dateMiami Valley Lighting | November 28, 2011, the date of the closing of the mergerMiami Valley Lighting, LLC is a wholly-owned subsidiary of DPL established in 1985 to provide street and Dolphin Sub, Inc.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 and, in some cases, insurance services to partner companies relative to jointly-owned facilities operated by AES Ohio Generation |
| MW | Megawatt |
| MWh | Megawatt hour |
| NAAQS | National Ambient Air Quality Standards |
| NAV | Net asset value |
|
| |
GLOSSARY OF TERMS (cont.) |
Abbreviation or Acronym | Definition |
| 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 |
NSPS | New Source Performance Standards |
| NSR | New Source Review: a preconstruction permitting program regulating new or significantly modified sources of air pollution |
NYMEX | New York Mercantile Exchange |
OCC | Ohio Consumers’ Counsel |
| OCI | Other Comprehensive Income |
| Ohio EPA | Ohio Environmental Protection Agency |
| OTC | Over the counter |
| OVEC | Ohio Valley Electric Corporation, an electric generating company in which DP&L holdshas a 4.9% equity 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 |
PPM | Parts per million |
| PRP | Potentially Responsible Party |
| PUCO | Public Utilities Commission of Ohio |
ROE | Return on equity |
RPM | The Reliability Pricing Model was PJM’s capacity construct prior to the CP program |
| 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. |
SCR | Selective Catalytic Reduction |
| 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 |
SO3
| Sulfur Trioxide |
| SSO | Standard Service Offer represents the retail transmission, distribution and generation services offered by a utility through regulated rates, authorized by the PUCO |
SSR | Service Stability Rider |
T&D | DP&L’s electric transmission and distribution businesses, which distribute electricity to residential, commercial, industrial and governmental customers |
| TCJA | The Tax Cuts and Jobs Act of 2017 signed on December 22, 2017 |
TCRR-NU.S. | Transmission Cost Recovery Rider - NonbypassableUnited States of America |
| USD | U.S. dollar |
| USEPA | U. S. Environmental Protection Agency |
|
| |
GLOSSARY OF TERMS (cont.) |
Abbreviation or Acronym | Definition |
| USF | The Universal Service Fund (USF) is a statewide program which provides qualified low-income customers in Ohio with income-based bills and energy efficiency education programs |
| U.S. SBU | U. S. Strategic Business Unit, AES’ reporting unit covering the businesses in the United States, including DPL |
PART I
This report includes the combined filing of DPL and DP&L. DPL is a wholly-owned subsidiary of AES, a global power company. Throughout this report, the terms “we”, “us”, “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.
FORWARD–LOOKING STATEMENTS
Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of future economic performance, 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;
impacts of weather on retail sales and wholesale prices;
impacts of renewable energy generation, natural gas prices and other market factors on wholesale prices;
weather-related damage to our electrical system;
fuel, commodity and other input costs;
performance of our suppliers;
transmission and distribution system reliability and capacity;
purchased power costsregulatory actions and availability;
regulatory action,outcomes, including, but not limited to, the review and approval of our basic 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 large 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; |
| |
▪ | catastrophic events such as fires, explosions, cyber-attacks, 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; |
| |
| ▪ | 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; |
| |
| ▪ | the use of derivative contracts; |
| |
▪ | 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.
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 incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave consumers the right to choose theproviding electric generation supplier from whom they purchase retail generation service, however transmission and distributiondistribution services are still regulated. DP&L has the exclusive right to provide such service to its approximately 521,000 customers located in West Central Ohio. DP&L is required to procure and provide 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 100% of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in five 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 were transferred to AES Ohio Generation owns an affiliateundivided interest in a coal-fired generating facility and sells all 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 soldits energy and capacity into the wholesale market.
DPL’s other significant subsidiaries include AES Ohio Generation, which owns and operates coal-fired and peaking generating facilities from which it makes wholesale sales of electricity, and MVIC is our captive insurance company that provides insurance services to usDPL and our other subsidiaries. For additional information, see Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DPLDPL's wholly owns eachConsolidated Financial Statements and Note 1 – Overview and Summary of its subsidiaries.Significant Accounting Policies of Notes to DP&L's Financial Statements. All of DPL's subsidiaries are wholly-owned.
On December 8, 2017, AESAs an electric public utility in Ohio, Generation completedDP&L provides regulated transmission and distribution services to its customers as well as retail SSO electric service. DP&L's sales reflect the salegeneral 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 Miami Fortdecoupling rider approved in the DRO. See Note 3 – Regulatory Matters of Notes to DPL's Consolidated Financial Statements and Zimmer stationsNote 3 – Regulatory Matters of Notes to subsidiaries of Dynegy in accordance with an asset purchase agreement dated April 21, 2017. In addition, on December 15, 2017, AES Ohio Generation entered into an asset purchase agreementDP&L's Financial Statements for the sale of its Peaker assets to Kimura Power, LLC.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.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 twoone reportable operating segments,segment, the Transmission and Distribution segment and the GenerationUtility segment. See Note 1413 – Business Segments of the Notes to DPL’sDPL's Consolidated Financial Statements for additional information regarding DPL’s reportable segments.segment.
With the transfer of its generation assets on October 1, 2017, DP&L has only one reportable operating segment, the Transmission and Distribution segment.EMPLOYEES
EMPLOYEES
DPL and its subsidiaries employed 1,060659 people at January 31, 2018,2019, of which 660647 were employed by DP&L&L. . Approximately 60%57% of all DPL employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and DP&L and AES Ohio Generation each have the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted.
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
ELECTRIC OPERATIONS AND FUEL SUPPLY
2017 Summer Generating Capacity
(in MW)
DPL's present summer generating capacity is as follows:
|
| | | | | | | | | | | | |
| Summer Generating Capacity | Coal fired
(steam generation)
(percent of total) | | Combustion Turbines, Diesel Units and Solar
(percent of total) | | Total |
| DPL | 1,137 |
| | 54% | | 988 |
| | 46% | | 2,125 |
|
100%Consolidated Financial Statements and Note 12 – Related Party Transactions of DPL’s existing steam generating capacity is provided by generating units owned as tenants in common with Dynegy, Inc. and/or AEP Generation. As tenants in common, each company owns a specified share of each of these units, is entitledNotes to its share of capacity and energy output and has a capital and operating cost responsibility proportionate to its ownership share. Additionally, DP&L,&L's Duke Energy and Ohio Power Company own, as tenants in common, 880 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.
In 2017, DPL generated 95% of its electric output from coal-fired units and 5% from solar, oil and natural gas-fired units.
The following table sets forth DPL’s generating stations and, where indicated, those stations which are owned as tenants in common:
|
| | | | | | | | | | | | |
| | | | | | | | | Approximate Summer MW Rating |
| Station | | Ownership (1) | | Operating Company (2) | | Location | | DPL Portion (3) | | Total |
| Coal-fired Units | | | | | | | | |
| Killen - Unit 2 | | C (4) | | A | | Wrightsville, OH | | 402 |
| | 600 |
|
| Stuart - Units 2 through 4 | | C (4) | | A | | Aberdeen, OH | | 606 |
| | 1,731 |
|
| Conesville - Unit 4 | | C....... | | B | | Conesville, OH | | 129 |
| | 780 |
|
| Sub-total coal-fired | | | | | | | | 1,137 |
| | 3,111 |
|
| Solar, Combustion Turbines (CT) or Diesel | | | | | | | | |
| Hutchings CT Unit 7 | | W (5) | | A | | Miamisburg, OH | | 25 |
| | 25 |
|
| Yankee Units 1 - 7 | | W (5) | | A | | Centerville, OH | | 101 |
| | 101 |
|
| Yankee Solar | | W (5) | | A | | Centerville, OH | | 1 |
| | 1 |
|
| Monument Diesels | | W (5) | | A | | Dayton, OH | | 12 |
| | 12 |
|
| Tait Diesels | | W (5) | | A | | Dayton, OH | | 10 |
| | 10 |
|
| Sidney Diesels | | W (5) | | A | | Sidney, OH | | 12 |
| | 12 |
|
| Tait CT Units 1 - 7 | | W (5) | | A | | Moraine, OH | | 576 |
| | 576 |
|
| Killen CT | | C (4) | | A | | Wrightsville, OH | | 12 |
| | 18 |
|
| Stuart Diesels | | C (4) | | A | | Aberdeen, OH | | 3 |
| | 10 |
|
| Montpelier CT Units 1 - 4 | | W (5) | | A | | Poneto, IN | | 236 |
| | 236 |
|
| Sub-total Solar, CT or Diesel | | | | 988 |
| | 1,001 |
|
| | | | | | | | |
|
| | |
| Total summer generating capacity (approximate) | | | | 2,125 |
| | 4,112 |
|
| |
(1) | W = Wholly-owned; C = Commonly-owned |
| |
(2) | A = Operated by AES Ohio Generation; B = Operated by AEP Generation |
| |
(3) | DPL portion of commonly-owned generating stations
|
| |
(4) | DPL announced during 2017 that it plans on retiring the co-owned Stuart Station coal-fired and diesel-fired generating units and the co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018
|
| |
(5) | On December 15, 2017, AES Ohio Generation entered into an asset purchase agreement for the sale of these generating facilities. See Note 17 – Assets and Liabilities Held-For-Sale and Dispositions of Notes to DPL's Consolidated Financial Statements.
|
DP&L also owns a 4.9% equity ownership interest in OVEC, an electric generating company. OVEC has two electric generating stations located in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of 2,109 MW. DP&L’s share of this generation capacity is 103 MW.
We have all of the coal volume needed to meet our wholesale sales obligations for 2018 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government-imposed costs, counterparty performance and credit, scheduled/forced outages and generation station mix. Due to the installation of emission control equipment at certain commonly-owned units and barring any changes in the regulatory environment in which we operate, we expect to have balanced positions for SO2, NOx and renewable energy credits for 2018.
The gross average cost of fuel consumed per kWh was $2.09 per kWh, $2.30 per kWh and $2.48 per kWh in 2017, 2016 and 2015, respectively.
SEASONALITY
The power generation and delivery businesses arebusiness is seasonal, and weather patterns have a material effect on operating performance.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. Unusually mild summersDP&L's sales typically reflect the seasonal weather patterns and winters couldthe 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 results of operations, financial conditionoperating performance. Severe storms often damage transmission and cash flows.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 and AES Ohio Generation's wholesale electric rates are subject to regulation by the FERC under the Federal Power Act.
Ohio law establishes the process for determining SSO and non-bypassable rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate changes, the cost basis upon which the rates are set and other service-related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.
Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPLDPL. . 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&L. . See Note 3 – Regulatory Matters of Notes to DPL’sDPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s&L's Financial Statements.
COMPETITION AND REGULATION
Ohio Matters
Ohio Retail Rates
DP&L filed a settlement inan amended stipulation to its 2017 ESP case in January 2017 and filed an amended stipulation 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 forwardgoing-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 signatoryDRO approved, without modification, a stipulation and recommendation previously filed by DP&L, along with various intervening parties agreedand 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 six-year settlement that providesreturn on equity of 9.999% and a framework for energy rates and defines other components.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’sDPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s&L's Financial Statements.
The costs associated with providing high voltage transmission service and wholesale electric sales and ancillary services are subject to FERC jurisdiction. While 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.
On November 30, 2015,In December 2018, DP&L filed a distribution rate caseDistribution Modernization Plan (“DMP”) with the PUCO using a 12-month test yearproposing to invest $576.0 million in capital projects over the next 10 years. There are eight principal components of June 1, 2015 to May 31, 2016 to measure revenueDP&L’s DMP: 1) Smart Meters, 2) Self-Healing Grid, 3) Customer Engagement, 4) Enhancing Sustainability and expensesEmbracing Innovation. 5) Telecommunications, 6) Physical and a date certain of September 30, 2015 to measure its asset base.Cyber Security, 7) Governance and Analytics, and 8) Grid Modernization R&D.
These initiatives will also allow DP&L is seeking an increase to distribution revenuesbe ready to leverage and integrate Distributed Energy Resources into its grid, including demonstrations of $65.8 million per year.community solar, energy storage, microgrids, as well as Electric Vehicle charging infrastructure. If approved, DP&L has asked for recovery of certain regulatory assets.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 hasfiled 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 modified straight-fixed variable rate design in an effort to decouple distribution revenues from electric sales. If approved as filed, the rates aretwo-year extension. The extension request was set at a level expected to have an increasereduce 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 approximately 4% on a typical residential customer bill based on rates in effect at the time of the filing.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 CommissionPUCO on December 20, 2017. For additional information on this settlement agreement, see "Management's Discussion and Analysis of Financial Condition - Key Trends and Uncertainties - Regulatory Environment". DP&L recovers the costs of its compliance
with Ohio energy efficiency and renewable energy standards through separate riders which are reviewed and audited by the PUCO.
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 onwith 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 retirement of Stuart Unit 1; the sale of interests in the
Miami Fort and Zimmer stations to subsidiaries of Dynegy; the retirement of Stuart and a future adjustment that would be effective upon closing ofKillen; and the planned 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 for more information.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.
Competitive Generation
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 our generating units, but also on how AES Ohio Generation’s prices, terms and conditions compare to those of other suppliers.
As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities were required to join an RTO. 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.
Capacity Auction Price
The PJM capacity base residual auction for the 2020/21 period cleared at a price of $77/MW-day for our RTO area. The prices for the periods 2019/20, 2018/19, 2017/18,Like other electric utilities and 2016/17 were $100/MW-day, $165/MW-day, $152/MW-day and $134/MW-day, respectively, based on previous auctions. As discussed below, a new CP program was approved by the FERC, which has phased in and replaced the RPM as of the 2018/19 auction. During the phase-in period, the RPM auction results were modified based on transitional auctions that were conductedenergy marketers, AES Ohio Generation may sell or purchase electric products in the third quarterwholesale 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 2015. These estimates are discussed further within Commodity Pricing Risk inAES Ohio Generation to sell this electricity will depend not only on the Item 7A - Quantitativeperformance of its generating unit, but also on how AES Ohio Generation’s prices, terms and Qualitative disclosures about Market Risk.
conditions compare to those of other suppliers.
ENVIRONMENTAL MATTERS
DPL’s and DP&L'sfacilities and operations are subject to a wide range of federal, state and local environmental regulationslaws, rules and laws.regulations. The environmental issues that may affect us include: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.DPL installed emission control technology and is taking other measures to comply with required and anticipated reductions. As AES Ohio Generation is now operating these facilities, it is continuing to comply with these requirements; |
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 1211 – Contractual Obligations, Commercial Commitments and Contingencies – "Environmental Matters” of Notes to DPL’sDPL's Consolidated Financial Statements and Note 11 – Contractual Obligations, Commercial Commitments and Contingencies – "Environmental Matters" of Notes to DP&L’s&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 the operationour results of the power stations.operations, financial condition or cash flows.
Environmental Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on how much of a pollutant can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.
Cross-State Air Pollution Rule
On September 7, 2016, the USEPA finalized an update to the CSAPR to address the 2008 ozone NAAQS. CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from
emitting any air pollutant in an amount which will contribute significantly to any other state’s non-attainment, or interference with maintenance of, any NAAQS. The final rule found that NOx ozone season emissions in 22 states (including Ohio) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS. For these 22 states, the USEPA issued federal implementation plans that generally update existing CSAPR NOx ozone season emission budgets for electric generating units within these states and implement these budgets through modifications to the existing CSAPR NOx ozone season allowance trading program. Implementation began in the 2017 ozone season (May through September 2017). Affected facilities receive fewer ozone season NOx allowances in 2017 and later, possiblyresulting in the need to purchase additional allowances. 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 agreement to sell its Peaker assets, we do not expect any impact on our remaining generating assets to be material.
Mercury and Other Hazardous Air Pollutants
On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired EGUs. The standards include new requirements for emissions of mercury and a number of other heavy metals. The USEPA Administrator signed the final rule, now called MATS, on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012, with a compliance date of April 16, 2015. All of our operating EGUs are currently achieving compliance through control technologies in place.
On January 31, 2013, the USEPA finalized a rule regulating emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers and process heaters at major and area source facilities. This regulation affects five auxiliary boilers used for start-up purposes at DPL’s generation facilities. The regulation contains emissions limitations, operating limitations and other requirements. As of the date of this report, DPL is in material compliance with this rule.
National Ambient Air Quality Standards
On January 25, 2013, the USEPA published the 2012 PM 2.5 standard of 12.0 micrograms per cubic meter. On January 15, 2015, the USEPA published its final designations for the 2012 standard. No counties containing generating facilities owned or operated by DPL have been designated as non-attainment.
On October 1, 2015, the USEPA released a final rule lowering the 8-hour ozone standard from 0.075 to 0.070 ppm. The USEPA published its final ozone attainment designations on November 16, 2017, designating all counties in Ohio as attainment/unclassifiable. No generating facilities currently owned or operated by DPL are in non-attainment areas. In December 2013, eight northeastern states petitioned the USEPA to add nine upwind states, including Ohio, to the Ozone Transport Region, a group of states required to impose enhanced restrictions on NOx emissions. On November 3, 2017, the USEPA published a final rule denying the petition. On December 26, 2017, eight northeastern states filed a petition for review challenging the final rule denying the petition. In addition, Maryland petitioned the USEPA in November 2016, asking the USEPA to determine that 36 electric generating units emit pollutants that contribute to non-attainment of the ozone standards in their state. The Killen unit was on the list of 36 units. On September 27, 2017, the State of Maryland filed a complaint against the USEPA for failing to address its November 2016 CAA petition. In light of the scheduledplanned 2020 retirement of Conesville, the Killen unit, even if this petition is granted, we dofollowing environmental matters, regulations and requirements are now not expect any additional requirementsexpected to have a material impact on us.DPL:
Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. Additionally, on August 23, 2010, the USEPA implemented its revisions to its primary NAAQS for SO2 replacing the previous 24-hour standard and annual standard with a one-hour standard. As a result of DPL’s decision to retire its Stuart and Killen generating stations, the sale of the Miami Fort and Zimmer generating stationsThe CAA and the agreement to sell its Peaker assets, we do not expect any impact on our remaining generation assets to be material.following regulations
On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. In January 2017, the USEPA revised the rules governing submission of SIPs to implement the visibility programs, postponing the due date for the next SIP revisions until July 2021. We cannot determine the extent of the impact, if any, on our remaining operations until Ohio determines how BART will be implemented.
Carbon Dioxide and Other Greenhouse Gas Emissions
On December 22, 2015, the USEPA's final CO2 emission rules for existing power plants, the CPP became effective. The CPP provides for interim emissions performance rates that must be achieved beginning in 2022 and final emissions performance rates that must be achieved starting in 2030. Under the CPP, states are required to meet state-wide emission rate standards or equivalent mass-based standards, with the goal being a 32% reduction in total U.S. power sector emissions from 2005 levels by 2030. The CPP would require states to submit, by 2016, implementation plans to meet the standards or a request for an extension to 2018. If a state fails to develop and submit an approvable implementation plan, the USEPA will finalize a federal plan for that state. The full impact of the CPP would depend on the following:
whether and how the states in which the Company's U.S. businesses operate respond to the CPP;
whether the states adopt an emissions trading regime and, if so, which trading regime;
how other states respond to the CPP, which will affect the size and robustness of any emissions trading market; and
how other companies may respond in the face of increased carbon costs.
Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit Court. Pursuant to a court order issued in August 2017, the litigation is being held in indefinite abeyance pending further court order.
In addition, several states and industry groups filed petitions in the D.C. Circuit Court challenging the CPP and requested a stay of the rule while the challenge was considered. The D.C. Circuit Court denied the stay and granted requests to consider the challenges on an expedited basis. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. On March 28, 2017, the USEPA filed a motion in the D.C. Circuit Court to hold the challenges to both the CPP and the GHG NSPS in abeyance in light of an Executive Order signed the same day. On April 28, 2017, the D.C. Circuit Court issued orders holding the challenges to both rules in abeyance for 60 days, with subsequent extensions granted by the court. The most recent extension of the CPP litigation was set to expire in January 2018 but, on January 10, 2018, the USEPA filed a status report requesting that the court continue to hold the case in abeyance pending the conclusion of further rulemaking on the CPP. On October 16, 2017, the USEPA published in the Federal Register a proposed rule that would rescind the CPP. On December 28, 2017, the USEPA published an Advance Notice of Proposed Rulemaking to solicit comments as the USEPA considers a potential rule to establish emission guidelines to replace the CPP and limit GHG emissions from existing electric generating units under Section 111(d) of the CAA. Some states and environmental groups have opposed the USEPA’s most recent request to continue to hold the CPP appeals in abeyance and the D.C. Circuit Court has not yet acted upon the USEPA’s request.
Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the USEPA that rescinds or substantively revises the NSPS, it could impact any plans to construct and/or modify or reconstruct electric generating units in some locations, which may have a material impact on our business, financial condition or results of operations.
We will likely not know the answers to the above questions regarding the CPP until later in 2018 or potentially 2019. As the first compliance period would not end until 2025, and because we cannot predict whether the CPP will survive the legal challenges or be repealed or replaced through rulemaking, it is too soon to determine the CPP's potential impact on our business, operations or financial condition, but any such impact could be material.
During 2017, approximately 95% of the energy we produced was generated by coal. As a result of DPL’s decision to retire its Stuart and Killen generating stations, the sale of the Miami Fort and Zimmer generating stations and the agreement to sell its Peaker assets, we do not expect any impact on our remaining generating assets to be material.
Litigation, Notices of Violation and Other Matters Related to Air Quality
| |
| ◦ | CSAPR and associated updates; |
| |
| ◦ | MATS and any associated regulatory or judicial processes; |
| |
| ◦ | 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. Continued complianceGiven that all of the commitments have been met and with the consent decree, as amended, is not expected to have a material effect onretirement of the Stuart generating station, DPL’sDPL resultsand the other owners plan to submit a request for termination of operations, financial condition or cash flows in the future.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 (now co-owned(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.
On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received an NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio SIP and permits for the station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, the USEPA issued an NOV to Duke Energy for excess emissions at the Zimmer generation station. In addition, Duke Energy received an NOV from the USEPA dated December 16, 2014 alleging violations in opacity at the Zimmer generating station on two dates in 2014. DP&L was a co-owner of the Zimmer generating station at the time and could be affected by the eventual resolution of these matters. Dynegy is expected to act on behalf of itself and its co-owners, including DPL, with respect to these matters. DPL sold its interest in the Zimmer generating station to Dynegy on December 8, 2017.
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. WeOperations 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 StationEGU, 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. As a resultWe cannot predict the outcome of the cessation of operations of the six coal-fired units at the Hutchings Station, we believe that the USEPA is unlikely to pursue the NSR complaint.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, and 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 (described in further detail below) are now not expected to have a material impact on DPL with respect to these generating stations: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;2015 and
water rules for Selenium published July 13, 2016.
Clean Water Act – Regulation of Water Intake
On May 19, 2014, commonly referred to as the USEPA finalized new regulations pursuant to the CWA governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. Although we do not yet know the full impact the final rules will have on our operations, material changes to the intake structure at the Stuart Station to reduce impingement with the possibility of additional site-specific requirements for reducing entrainment could be
required. With DPL's decision to retire the Stuart generating station, we do not believe the final rules will have a material impact on operations at that station or any of the other DPL-operated facilities.ELG rules.
Clean Water Act – Regulation of Water Discharge
On January 7, 2013, the Ohio EPA issued a final NPDES permit to the Stuart generating stationStation 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 generating stationStation we do not expect this to have a material impact on us.
On November 3, 2015, the USEPA published its final ELG rule to reduce toxic pollutants discharged into waterways by power plants. Under the provisions of the final rule, discharges from fly ash ponds and bottom ash ponds will eventually be prohibited and treatment will be required for water discharges associated with flue gas desulfurization equipment. Legal challenges to the ELG rule are pending before the U.S. Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) and are currently being held in abeyance during review of the rule and possible rulemaking. On September 18, 2017, the USEPA published a final rule in the Federal Register delaying certain compliance dates of the ELG and withdrew the stay issued by the Trump Administration on April 25, 2017. If we were required to fully implement the requirements of the rule based on current operations, we anticipate that we would be required to make significant capital expenditures that could have a material adverse effect on our results of operations, financial condition and cash flows. However, as a result of the decision to retire the Stuart and Killen generating stations, we do not expect the ELG rule to have a material impact on either of these two stations. We may have continuing obligations under the ELG rule at our Conesville EGU.
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 iswas scheduled to be held in 2019.2019, 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 2019 trial.vapor intrusion trial proceeding. The courtDistrict 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 2019 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.
In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on its results of operations, financial condition or cash flows.
Regulation of Ash PondsCCR
The USEPA's final CCR rule became effective onOn October 19, 2015. Generally,2015, a USEPA rule regulating CCR under the rule regulates CCRResource Conservation and Recovery Act as nonhazardous solid waste and establishes nationalbecame effective. The rule established nationally applicable minimum criteria for existingthe disposal of CCR in new and new CCRcurrently operating landfills and
existing and new CCR surface impoundments, (ash ponds), including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements and post-closure care. In 2015, DPL increasedThe primary enforcement mechanisms under this regulation would be actions commenced by the ARO relatedstates 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 ash ponds byimplement the
CCR rule through a net $40.3 million asstate permitting program, or if the state chooses not to participate, a result of additional information obtained in responsepossible federal permit program. EPA has indicated that they will implement a phased approach to this rule. 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.
In November 2016, Duke Energy announced a settlement with the U.S. Attorney's Office for the Southern District of Ohioassociated with an NOV issued by the USEPA for a fuel oil spill at the Beckjord station in 2014. DP&L at that time co-owned 50% of one of the units at the station and was generally responsible for that percentage of that unit’s costs. The settlement includes a $1.0 million fine and a requirement to clean up the spill at the station. DP&L's portion of the fine and cleanup costs associated with this spill, based on its prior ownership of that one unit at the station, has not yet been determined.
Capital Expenditures for Environmental Matters
DPL’s environmental capital expenditures were approximately $0.5 million, $6.1 million and $6.5 million in 2017, 2016 and 2015, respectively. DPL has projected $0.6 million in environmental-related capital expenditures for 2018.
ELECTRIC SALES AND REVENUES
The following table sets forth DPL’s, DP&L's and DPLER's electric sales for the years ended December 31, 2017, 2016 and 2015, as well as billed electric customers as of December 31, 2017, 2016 and 2015.
|
| | | | | | | | | | | | | | | | | | |
| | | Year ended December 31, 2017 | | Year ended December 31, 2016 | | Year ended December 31, 2015 |
| | | Electric sales (millions of kWh) | | Billed electric customers (end of period) | | Electric sales (millions of kWh) | | Billed electric customers (end of period) | | Electric sales (millions of kWh) | | Billed electric customers (end of period) |
| | | | | | | | | | | | | |
DPL (a) | | 14,771 |
| | 521,609 |
| | 16,757 |
| | 519,128 |
| | 14,738 |
| | 516,708 |
|
| | | | | | | | | | | | | |
DP&L (b) | | 4,116 |
| | 521,609 |
| | 3,856 |
| | 519,128 |
| | 3,896 |
| | 516,708 |
|
| | | | | | | | | | | | | |
DPLER (c) | | — |
| | — |
| | — |
| | — |
| | 5,928 |
| | 124,866 |
|
| |
(a) | Electric sales exclude 1,976 million kWh relating to DPLER for the year ended December 31, 2015, and Billed electric customers excludes DPLER customers outside of the DP&L service territory of 14,147 customers for the year ended December 31, 2015.
|
| |
(b) | Excluded from this line are 8,120 million KWh, 12,302 million KWh and 12,528 KWh of power relating to generation sales for the years ended December 31, 2017, 2016 and 2015, respectively, as the generation business was classified as a discontinued operation for the periods listed. |
| |
(c) | This row includes all customers and sales of DPLER, both within and outside of the DP&L service territory.
|
HOW TO CONTACT DPL AND DP&L
DPL is a regional energy company incorporated in 1985 under the laws of Ohio. Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio 45432 - telephone 937-259-7215.937-259-7215. 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.
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’sDPL's audited Consolidated Financial Statements and concerning DP&L set forth in the Notes to DP&L’s&L's audited 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. As we continue to implementIn light of executing on our plan to exit coal-fired generation, risks applicable to our generation business will continue to lessen,and the risks associated with that business have significantly lessened, such as risks associated with operations of the generation plants and with greenhouse gas emission requirements.
Our electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costsand other significant liabilities for which we may not have adequate insurance coverage.
We operate coal, oil and natural gas generating facilities, which involve certain risks that can adversely affect energy costs, output and efficiency levels. These risks include:
increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;
unit or facility outages due to a breakdown or failure of equipment or processes;
disruptions in the availability or delivery of fuel and lack of adequate inventories;
shortages of or delays in obtaining equipment;
loss of cost-effective disposal options for solid waste generated by the facilities;
labor disputes or work stoppages by employees;
accidents and injuries;
reliability of our suppliers;
inability to comply with regulatory or permit requirements;
operational restrictions resulting from environmental permit limitations or governmental interventions;
construction delays and cost overruns;
disruptions in the delivery of electricity;
the availability of qualified personnel;
events occurring on third party systems that interconnect to and affect our system;
operator error; and
catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, sabotage acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences affecting our generating facilities, as well as our transmission and distribution systems.
The above risks could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures and/or increased fuel and purchased power costs, any of which could have a material adverse effect on our financial condition, results of operations and cash flows. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action and/or reduced wholesale revenues.
Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.
The hazardous activities described above can also cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a
defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any such losses not covered by insurance could have a material adverse effect on our results of operations, financial condition and cash flows.
In addition, operation of our owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels and likely result in decreased revenues and/or increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows.
We have constructed and placed into service FGD facilities and other equipment to better monitor environmental compliance at our base-load generating stations. If there is significant operational failure of such equipment at the generating stations, we may not be able to meet emission requirements at such generating stations. These events could result in a substantial increase in our operating costs. Depending on the degree, nature, extent, or willfulness of any failure to comply with environmental requirements, including those imposed by any consent decrees, such non-compliance could result in increased operating costs, the imposition of penalties or the shutting down of the affected generating stations, which could have a material adverse effect on our results of operations, financial condition and cash flows.
We are reliant upon the performance of co-owned EGUs which are operated by our co-owners for approximately 11% of our base-load generation.
Since approximately 11% of our base-load generation is derived from co-owned EGUs operated by our co-owners, poor operational performance by our co-owners, misalignment of co-owners’ interests with our own or lack of control over costs (such as fuel costs) incurred at these stations could have an adverse effect on us. In addition, any sale of these co-owned EGUs by a co-owner to a third party could enhance the risk of a misalignment of interests, lack of cost control and other operational failures.
We may not always be able to recover our costs to deliver electricity to our retail customers. The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO.
In Ohio, retail generation rates are 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, ownership of generation assets, transition to or 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.
On November 30, 2015, DP&L filed with the PUCO a distribution rate case to establish new distribution rates. There can be no assurance that any rate case or filing we make with the PUCO, including any settlement with parties to any case, will be approved as filed or on a timely basis by the PUCO, and if approval is not made on a timely basis or if the approval provides for terms that are more adverse than those submitted for approval, our results of operations, financial condition, cash flows, and DPL's ability to meet long-term obligations, in the periods beyond twelve months from the date of this report, could be materially impacted. DP&L’s 2015 distribution rate case filing, most recent ESP filing and certain other regulatory filings and matters, are further discussed in Item 1 - Business - Competition and Regulation, as well as in Note 3 – Regulatory Matters of Notes to DPL’s Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s Financial Statements.
Our increased costs due to renewable energy and energy efficiency requirements may not be fully recoverable in the future.
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 adversely affect our results of operations, financial condition and cash flows.
The availability and cost of fuel and other materials have experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from availability and price volatility.
Our business is sensitive to changes in the price of fuel used in generation facilities. In addition, changes in the prices of steel, copper and other materials can also have a significant impact on our costs. Any changes in these costs could affect the margins.
Our approach was to hedge the fuel costs for our anticipated electric sales. However, we may not be able to hedge the entire exposure of our operations from fuel price volatility. In addition, market prices for power sales are volatile and not subject to control by any market participant. If market prices for power sales do not fully recover the costs of fuel, we would take steps to reduce our contract takes of fuel, but contractual requirements to take minimum amounts could cause adverse financial effects. If in the future we are unable to timely or fully recover our fuel and purchased power costs from the market, it could have a material adverse effect on our results of operations, financial condition and cash flows.
DPL is a co-owner of a generation facility where it is a non-operating owner. DPL does not procure or have control over the fuel and other materials for this facility but is responsible for its proportionate share of the cost of fuel procured at this facility. Co-owner operated facilities do not always have realized costs that are equal to our co-owner's projections of such costs, and we are responsible for our proportionate share of any increase in actual costs.
Wholesale power marketing activities may add volatility to earnings.
We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the PJM day-ahead and real-time markets. As part of these strategies, we may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. The earnings from our wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity, beyond that needed to meet firm service requirements. In order to reduce the risk of volatility in earnings from wholesale marketing activities, we may at times enter into forward contracts to hedge such risk. If our hedging procedures do not operate as planned we may experience losses. In addition, the introduction of additional renewable energy, demand response or other energy supply into the PJM market could have the effect of reducing the demand for wholesale energy from other sources. This additional generation could have the impact of reducing market prices for energy and could reduce our opportunity to sell coal-fired and gas generation into the PJM market, thereby reducing our wholesale sales. Additionally, decreases in natural gas prices in the U.S. have the impact of reducing market prices for electricity, which can reduce our ability to sell excess generation on the wholesale market, as well as reduce our profit margin on wholesale sales.
Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DPL sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal price optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread, adjusted for any quality differentials. Sales of coal arenegatively affected by a rangelack of growth or a decline in the number of customers.
Customer growth is affected by a number of factors including price volatility
among the different coal basinsoutside our control, such as population changes, job and qualities of coal, variations in power demandincome growth, housing starts, new business formation and the market priceoverall level of power compared toeconomic activity. A lack of growth, or a decline, in the cost to produce power. These factors could cause the amount and pricenumber of coal we sell to fluctuate, whichcustomers in our service territory could have a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DPLand may sell its excess emission allowances, including NOXcause us to fail to fully realize anticipated benefits from investments and SO2 emission allowances, from time to time. Sales of any excess emission allowances are affected by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory for sale and changes to the regulatory environment, including the implementation of CSAPR. These factors could cause the amount and price of excess emission allowances DPL sells to fluctuate, which could have a material adverse effect on DPL’s results of operations, financial condition and cash flows for any particular period. Although there has been overall reduced trading activity in the annual NOX and SO2 emission allowance trading markets in recent years, the adoption of regulations that regulate emissions or establish or modify emission allowance trading programs could affect the emission allowance trading markets and have a material effect on DPL’s emission allowance sales.
Regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risks associated with climate change, could have a material adverse impact on our results of operations, financial condition and cash flows.
One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions, including by effectively putting a cost on such emissions to create financial incentives to reduce them. In 2017, DPL emitted approximately 11 million tons of CO2 from its power plants. DPL uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. DPL’s CO2 emissions are calculated from actual fuel heat inputs and fuel type CO2 emission factors.
Any existing or future international, federal, state or regional legislation or regulation of GHG emissions could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors including, among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, the price and availability of offsets, the extent to which market-based compliance options are available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. As a result of these factors, our cost of compliance could be substantial and could have a material adverse impact on our results of operations, financial condition and cash flows. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our EGUs and our support facilities. Variations in weather conditions, primarily temperature and humidity, would also be expected to affect the energy needs of customers. A decrease in energy consumption by our customers could decrease our revenues. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired EGUs. If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a material adverse effect on our results of operations, financial condition and cash flows.
In addition to the rules already in effect, regulatory initiatives regarding GHG emissions may be implemented in the future, although at this time we cannot predict if, how, or to what extent such initiatives would affect us. Generally, costs to comply with any regulations implemented to reduce GHG emissions, including those already promulgated, are part of the costs of providing electricity to our customers. While we might seek recovery for such costs, there can be no assurance that the PUCO will approve such requests or that we will be able to recover such costs. Concerns over GHG emissions and their effect on the environment have led and could lead further to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial
condition and cash flows. See Item 1 - Business - Environmental Matters for addition information of environmental matters impacting us, including those relating to regulation of GHG emissions.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 ashcoal combustion residuals and other materials, some of which may be defined as hazardous materials; the use and discharge of water used in generation boilers and for cooling purposes;materials, the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. WeSuch 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 (such as reductions in mercury and other hazardous air pollutants, SO3 and further reductions in GHG emissions as discussed in more detail in the previous risk factor) and limits on water use and discharge.future. Environmental laws, rules and regulations also generally 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 inspections and other government authorizations required to operate our business, then our operations could be prevented, delayed or subject to additional costs. A violation of environmental laws, 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. With respect to our largest EGU, the Stuart generating station, we are also subject to continuing compliance requirements related to NOX, SO2 and particulate matter emissions under DP&L’s consent decree with the Sierra Club. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. DPL owns a non-controllingan 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.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.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. For example, the amount of capital expenditures required to comply with environmental laws or regulations could be impacted by the outcome of the USEPA’s NOVs described in this Annual Report on Form 10-K. See Item 1 - Business - Environmental Matters for a more comprehensive discussion of these and other environmental matters impacting us.
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 commodity and financial risks. These trades are affected by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commoditiesinterest rates and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts, a counterparty failing to perform or the underlying transactions which the instruments are intended to hedge failing to materialize, which could result in a material adverse effect on our results of operations, financial condition and cash flows.
The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.
In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The occurrence of any of these events could have ana 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. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may
require us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.
On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM, a regional transmission organization. The price at which we can sell our generation capacity and energy is now dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJM’s business rules. While we can continue to make bilateral transactions to sell our generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM. To the extent we sell electricity into the power markets on a contractual basis, we are not guaranteed any rate of return on our capital investments through mandated rates. The results of the PJM capacity auction are impacted by the supply and demand of generation and load and may also be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources and other factors. Auction prices could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows. We cannot predict the outcome of future auctions, but low auction prices could have a material adverse effect on our results of operations, financial condition and cash flows.
The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. Various proposals and proceedings before the FERC may cause transmission rates to change from time to time. In addition, PJM has been developingdeveloped 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 basednon-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, itsuch costs could have a material adverse effect on our results of operation,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 87 – DebtLong-term debt of Notes to DPL’sDPL's Consolidated Financial Statements and Note 7 – DebtLong-term debt of Notes to DP&L’s&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.
Under the PJM Capacity Performance program, we could be subject to substantial changes in capacity income and/or penalties.
As the owner of generation that is a “capacity resource” within PJM, DPL is subject to mandatory requirements to participate in PJM markets. The Capacity Performance program offers the potential for higher capacity prices paired with higher penalties for non-performance during times of high electricity demand. Any such penalties could have a material adverse effect on our results of operations, financial condition and cash flows. See Item 1 - Business - Competition and Regulation for additional information about the PJM program.
Our transmission and distribution system is subject to 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, plantfacility outages, labor disputes, accidents or injuries, operator error or inoperability of key infrastructure internal or external to us.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 global economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges currently affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in thea normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic conditions improve. Some of our suppliers, customers, and other counterparties and others with whom we transact business may also experience financial difficulties, which may impact their ability to fulfill their obligations to us.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, 2017,2018, the carrying value of DPL's debt was $1,705.1$1,475.9 million and the carrying value of DP&L's debt was $646.6$586.1 million. Of DP&L's indebtedness, there was $640.6$576.1 million of First Mortgage Bonds, tax-exempt bonds and a term loan outstanding as of December 31, 2017,2018, 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 the following: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 at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms, or at all, to refinance our debt as it becomes due. For a further discussion of our outstanding debt obligations, see Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition,
Liquidity and Capital Requirements and Note 87 – DebtLong-term debt of Notes to DPL’sDPL's Consolidated Financial Statements and Note 7 – DebtLong-term debt of Notes to DP&L’s&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 selectedselect 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. AsWhen 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 environmental upgrades, improvements to generation, transmission and distribution facilities, as well as other initiatives. As a result, we may engage contractors and enter into agreements to acquire necessary materials and/or obtain required construction related services. In addition, some contracts
may provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause construction delays. It could also subject us to enforcement action by regulatory authorities to the extent that such a contractor failure resulted in a failure by DP&L to comply with requirements or expectations, particularly with regard to the cost of the project. As a result ofIf 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. We are currently unable to predict the long-term impact, if any, to our results of operations, financial condition and cash flows as a result of these rules and regulations. Complying with the regulatory environment to which we are subject requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business that could have a material adverse effect on our results of operations, financial condition and cash flows.
We may be subject to material litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time which may require us to expend significant funds to address. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition and cash flows. Asbestos and other regulated substances are, and may continue to be, present at our facilities. Wefacilities, and we have been named as a defendant in asbestos litigation, which at this time is not expected to be material to us.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 impactadverse effect on our results of operations.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. We also have policies and procedures in place to mitigate excessive risk-taking by employees since excessiveExcessive risk-taking by our employees to achieve performance targets, through mitigated by policies and procedures, could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements with employees who are members of a union. Over half of our employees are represented by a collective bargaining agreement that after initially being extended, expiredexpires on JanuaryOctober 31, 2018.2020. 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 adversely affecthave a material adverse effect on our results of operations, financial condition and cash flows and financial condition.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 and AES Ohio Generation.. As such, DPL’s cash flow is largely dependent on the operating cash flows of DP&L and its ability to pay cash to DPLDPL. . 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 87 – DebtLong-term debt of Notes to DPL’sDPL's Consolidated
Financial Statements and Note 7 – DebtLong-term debt of Notes to DP&L’s&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’sDPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s&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 acertain capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance.levels. See Note 1110 – 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 DPLDPL.. After the fixed-asset impairments recorded during the first quarter of 2017 and the second and fourth quarters of 2016 and as of December 31, 2017, DP&L's equity ratio was 33% and its retained earnings balance was negative. While we do not expect any of the foregoing to significantly affect DP&L’s ability to pay funds to DPL in the near future, a significant limitation on DP&L’s ability to pay dividends or loan or advance funds to DPL 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 in DPL's and DP&L'son 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 1517 – Fixed-asset Impairments ofimpairments or Notes to DPL’sDPL's Consolidated Financial Statements for more information on the impairment of fixed assets.
|
|
| Item 1B – Unresolved Staff Comments |
None.
Information relating to our properties is contained in Item 1 – Business – Electric Operations and Fuel Supply and Note 4 – Property, Plant and Equipment of Notes to DPL's Consolidated Financial Statements and Note 4 – Property, Plant and Equipment of Notes to DP&L's Financial Statements.
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. We also own aThese properties include our distribution service center in Dayton, Ohio.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, 2017.2018.
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 4 – Mine Safety Disclosures |
Not applicable.
PART II
|
|
| Item 5 – Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
All of the outstanding common stock of DPL is owned indirectly by AES and directly by a wholly-owned subsidiary of AES. As a result, ourDPL’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 2016 and 2015,2016, 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. DividendsReturn of capital payments and dividends on common shares in the amountamounts of $43.8 million, $39.0 million $70.0 million and $50.0$70.0 million were declared and paid in the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. DP&L declared and paid dividends on preferred shares of $0.7 million in the year ended December 31, 2016 and $0.9 million in the year ended December 31, 2015.2016.
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 ofon 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, 2017,2018, DPL’s leverage ratio was at 1.501.47 to 1.00 and DPL’s senior long-term debt rating from all threea major credit rating agenciesagency was below investment grade. As a result, as of December 31, 2017,2018, 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 1110 – Equity for more information and Note 98 – 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 1110 – Equity of Notes to DPL's Consolidated Financial Statements for more information and Note 10 – Equity of Notes to DP&L's Financial Statements.
|
|
| Item 6 – Selected Financial Data |
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 2013 and 2014 and the total electric sales and Balance Sheet Data for DP&L for 20132014 - 2015 are not comparable to the Statements of Operations Data for 2015 - 20172018 and the total electric sales and Balance Sheet Data for 2016 and 2017,- 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, | | Years ended December 31, |
| $ in millions except per share amounts or as indicated | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| Total electric sales (millions of kWh) | | 14,771 |
| | 16,757 |
| | 14,738 |
| | 14,695 |
| | 15,702 |
| | 15,728 |
| | 14,679 |
| | 15,406 |
| | 20,756 |
| | 19,060 |
|
| Statements of Operations Data | | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 1,236.9 |
| | $ | 1,427.3 |
| | $ | 1,612.8 |
| | $ | 1,716.5 |
| | $ | 1,579.0 |
| | $ | 775.9 |
| | $ | 743.9 |
| | $ | 834.2 |
| | $ | 1,612.8 |
| | $ | 1,716.5 |
|
Goodwill impairment (a) | | $ | — |
| | $ | — |
| | $ | 317.0 |
| | $ | — |
| | $ | 306.3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 317.0 |
| | $ | — |
|
Fixed-asset impairment (b) | | $ | 175.8 |
| | $ | 859.0 |
| | $ | — |
| | $ | 11.5 |
| | $ | 26.2 |
| | $ | 2.8 |
| | $ | — |
| | $ | 23.9 |
| | $ | — |
| | $ | 11.5 |
|
| Operating income / (loss) | | $ | (6.0 | ) | | $ | (683.9 | ) | | $ | (109.9 | ) | | $ | 230.7 |
| | $ | (77.4 | ) | | $ | 135.5 |
| | $ | 105.2 |
| | $ | 119.0 |
| | $ | (109.9 | ) | | $ | 230.7 |
|
| Income / (loss) from continuing operations | | $ | (94.6 | ) | | $ | (514.5 | ) | | $ | (251.4 | ) | | $ | 57.2 |
| | $ | (225.6 | ) | | $ | 31.2 |
| | $ | (1.5 | ) | | $ | 14.8 |
| | $ | (251.4 | ) | | $ | 57.2 |
|
| Income / (loss) from discontinued operations, net of tax | | $ | — |
| | $ | 29.3 |
| | $ | 12.4 |
| | $ | (131.8 | ) | | $ | 3.6 |
| | $ | 38.9 |
| | $ | (93.1 | ) | | $ | (500.0 | ) | | $ | 12.4 |
| | $ | (131.8 | ) |
| Net loss | | $ | (94.6 | ) | | $ | (485.2 | ) | | $ | (239.0 | ) | | $ | (74.6 | ) | | $ | (222.0 | ) | |
| Construction additions | | $ | 108.0 |
| | $ | 140.0 |
| | $ | 132.0 |
| | $ | 116.0 |
| | $ | 114.0 |
| |
| 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 | | $ | 2,049.2 |
| | $ | 2,419.2 |
| | $ | 3,324.7 |
| | $ | 3,559.1 |
| | $ | 3,699.3 |
| | $ | 1,883.1 |
| | $ | 2,049.2 |
| | $ | 2,419.2 |
| | $ | 3,324.7 |
| | $ | 3,559.1 |
|
Long-term debt (c) | | $ | 1,700.4 |
| | $ | 1,828.7 |
| | $ | 1,420.5 |
| | $ | 2,120.9 |
| | $ | 2,262.0 |
| | $ | 1,372.3 |
| | $ | 1,700.2 |
| | $ | 1,828.7 |
| | $ | 1,420.5 |
| | $ | 2,120.9 |
|
| Redeemable preferred stock of subsidiary | | $ | — |
| | $ | — |
| | $ | 18.4 |
| | $ | 18.4 |
| | $ | 18.4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18.4 |
| | $ | 18.4 |
|
| Total common shareholder's equity / (deficit) | | $ | (584.3 | ) | | $ | (587.6 | ) | | $ | (80.6 | ) | | $ | 148.2 |
| | $ | 239.5 |
| | $ | (471.7 | ) | | $ | (584.3 | ) | | $ | (587.6 | ) | | $ | (80.6 | ) | | $ | 148.2 |
|
| |
| (a) | Goodwill impairments of $317.0 million and $306.3 million recorded in 2015 and 2013, respectively. 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 ($114.3and $835.2 million net of tax), $859.0 million ($558.3 million net of tax), $11.5 million ($7.5 million net of tax) and $26.2 million ($17.0 million net of tax) were recorded in 2017 and 2016, 2014 and 2013, respectively.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, | | Years ended December 31, |
| $ in millions except per share amounts or as indicated | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Total electric sales (millions of kWh) (a) | | 4,116 |
| | 3,856 |
| | 3,896 |
| | 18,613 |
| | 19,423 |
| | 15,194 |
| | 14,401 |
| | 15,008 |
| | 26,394 |
| | 28,634 |
|
| Statements of Operations Data | | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 720.0 |
| | $ | 808.0 |
| | $ | 857.0 |
| | $ | 1,668.3 |
| | $ | 1,551.5 |
| | $ | 738.7 |
| | $ | 720.0 |
| | $ | 808.0 |
| | $ | 857.0 |
| | $ | 1,668.3 |
|
Fixed-asset impairment (b)(a) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 86.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Operating income | | $ | 120.6 |
| | $ | 168.1 |
| | $ | 222.2 |
| | $ | 188.8 |
| | $ | 139.9 |
| | $ | 135.1 |
| | $ | 122.1 |
| | $ | 169.0 |
| | $ | 222.2 |
| | $ | 188.8 |
|
| Income from continuing operations | | $ | 57.4 |
| | $ | 97.6 |
| | $ | 130.0 |
| | $ | 114.1 |
| | $ | 82.7 |
| | $ | 86.7 |
| | $ | 57.4 |
| | $ | 97.6 |
| | $ | 130.0 |
| | $ | 114.1 |
|
| Loss from discontinued operations, net of tax | | $ | (40.4 | ) | | $ | (870.3 | ) | | $ | (23.6 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (40.4 | ) | | $ | (870.3 | ) | | $ | (23.6 | ) | | $ | — |
|
| Net income / (loss) attributable to common stock | | $ | 17.0 |
| | $ | (773.4 | ) | | $ | 105.5 |
| | $ | 114.1 |
| | $ | 82.7 |
| | $ | 86.7 |
| | $ | 17.0 |
| | $ | (773.4 | ) | | $ | 105.5 |
| | $ | 114.1 |
|
Construction additions (c) | | $ | 83.0 |
| | $ | 88.0 |
| | $ | 91.0 |
| | $ | 112.0 |
| | $ | 111.0 |
| |
| Capital expenditures | | | $ | 93.1 |
| | $ | 101.7 |
| | $ | 128.3 |
| | $ | 127.0 |
| | $ | 114.2 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Balance Sheet Data (end of period): | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 1,689.4 |
| | $ | 2,035.1 |
| | $ | 3,359.6 |
| | $ | 3,328.8 |
| | $ | 3,300.4 |
| | $ | 1,819.6 |
| | $ | 1,695.9 |
| | $ | 2,035.1 |
| | $ | 3,359.6 |
| | $ | 3,328.8 |
|
Long-term debt (d)(b) | | $ | 642.0 |
| | $ | 731.5 |
| | $ | 313.6 |
| | $ | 868.2 |
| | $ | 865.3 |
| | $ | 581.5 |
| | $ | 642.0 |
| | $ | 731.5 |
| | $ | 313.6 |
| | $ | 868.2 |
|
| Redeemable preferred stock | | $ | — |
| | $ | — |
| | $ | 22.9 |
| | $ | 22.9 |
| | $ | 22.9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 22.9 |
| | $ | 22.9 |
|
| Total common shareholder's equity | | $ | 330.7 |
| | $ | 362.3 |
| | $ | 1,212.7 |
| | $ | 1,143.4 |
| | $ | 1,204.0 |
| | $ | 445.3 |
| | $ | 330.7 |
| | $ | 362.3 |
| | $ | 1,212.7 |
| | $ | 1,143.4 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Number of shareholders - preferred stock | | — |
| | — |
| | 180 |
| | 186 |
| | 186 |
| | — |
| | — |
| | — |
| | 180 |
| | 186 |
|
| |
| (a) | Excluded from this line are 8,120 million KWh, 12,302 million KWh and 12,528 KWh of power relating to generation sales for the years ended December 31, 2017, 2016 and 2015, respectively, as the generation business was classified as a discontinued operation for these periods. |
| |
(b) | Fixed-asset impairment of $86.0 million ($55.9 million net of tax) was recorded in 2013. Fixed-asset impairment of $1,353.5 million ($879.8 million net of tax) in 2016 washas been reclassified to discontinued operations. |
| |
(c) | Excluded from this line are $5.0 million, $31.0 million and $33.0 million of construction additions relating to the generation business for the years ended December 31, 2017, 2016 and 2015, respectively, as the generation business was classified as a discontinued operation for these periods. |
| |
(d)(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.Factors. For a list of certain abbreviations or acronyms in this discussion, see Glossary of Terms at the beginning of this Form 10-K.
Key topics in Management's Discussion and AnalysisEXECUTIVE SUMMARY
Our discussion covers the following:
Review of Results of Operations
| |
▪ | DPL - Generation Segment
|
Key Trends and Uncertainties
Capital Resources and Liquidity
Critical Accounting Estimates
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 | | $ | 15.9 |
|
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 Inc.
DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L&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, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Revenues: | | | | | | | | | | | | |
| Retail | | $ | 641.7 |
| | $ | 738.7 |
| | $ | 785.2 |
| | $ | 656.9 |
| | $ | 641.5 |
| | $ | 738.5 |
|
| Wholesale | | 382.3 |
| | 477.7 |
| | 598.2 |
| | 52.0 |
| | 31.9 |
| | 27.1 |
|
| RTO revenue | | 58.0 |
| | 62.4 |
| | 70.1 |
| | 43.2 |
| | 47.4 |
| | 46.5 |
|
| RTO capacity revenues | | 143.9 |
| | 137.4 |
| | 150.4 |
| | 14.4 |
| | 12.1 |
| | 11.0 |
|
| Other revenues | | 11.0 |
| | 11.1 |
| | 8.8 |
| | 9.4 |
| | 11.0 |
| | 11.1 |
|
| Mark-to-market gains | | — |
| | — |
| | 0.1 |
| |
| Total revenues | | 1,236.9 |
| | 1,427.3 |
| | 1,612.8 |
| | 775.9 |
| | 743.9 |
| | 834.2 |
|
| Cost of revenues: | | | | | | | | | | | | |
| Fuel cost: | | | | | | | |
| Fuel | | 211.6 |
| | 275.4 |
| | 263.1 |
| |
| Gains from sale of coal | | (1.3 | ) | | (6.6 | ) | | (3.0 | ) | |
| Mark-to-market gains | | — |
| | — |
| | (0.3 | ) | |
| Net fuel cost | | 210.3 |
| | 268.8 |
| | 259.8 |
| | 17.5 |
| | 9.0 |
| | 17.4 |
|
| Purchased power: | | | | | | | | | | | | |
| Purchased power | | 255.5 |
| | 322.0 |
| | 336.1 |
| | 244.9 |
| | 231.4 |
| | 258.1 |
|
| RTO charges | | 70.7 |
| | 78.4 |
| | 97.9 |
| | 57.8 |
| | 57.5 |
| | 59.7 |
|
| RTO capacity charges | | 14.7 |
| | 21.3 |
| | 122.5 |
| | 2.3 |
| | 2.1 |
| | 1.3 |
|
| Mark-to-market losses / (gains) | | (1.7 | ) | | (4.3 | ) | | 6.1 |
| |
| Net purchased power cost | | 339.2 |
| | 417.4 |
| | 562.6 |
| | 305.0 |
| | 291.0 |
| | 319.1 |
|
| | | | | | | | | | | | | |
| Total cost of revenues | | 549.5 |
| | 686.2 |
| | 822.4 |
| | 322.5 |
| | 300.0 |
| | 336.5 |
|
| | | | | | | | | | | | | |
| Gross margin | | 687.4 |
| | 741.1 |
| | 790.4 |
| | 453.4 |
| | 443.9 |
| | 497.7 |
|
| | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | |
| Operation and maintenance | | 327.6 |
| | 348.1 |
| | 361.3 |
| | 156.8 |
| | 186.1 |
| | 213.5 |
|
| Depreciation and amortization | | 106.9 |
| | 132.3 |
| | 134.6 |
| | 73.1 |
| | 76.1 |
| | 73.6 |
|
| General taxes | | 89.7 |
| | 85.7 |
| | 87.0 |
| | 73.5 |
| | 77.1 |
| | 68.4 |
|
| Goodwill impairment (Note 7) | | — |
| | — |
| | 317.0 |
| |
| Fixed-asset impairment (Note 15) | | 175.8 |
| | 859.0 |
| | — |
| |
| Other, net | | (6.6 | ) | | (0.1 | ) | | 0.4 |
| |
| 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 | | 693.4 |
| | 1,425.0 |
| | 900.3 |
| | 317.9 |
| | 338.7 |
| | 378.7 |
|
| | | | | | | | | | | | | |
| Operating loss | | (6.0 | ) | | (683.9 | ) | | (109.9 | ) | |
| Operating income | | | 135.5 |
| | 105.2 |
| | 119.0 |
|
| | | | | | | | | | | | | |
| Other expense, net | | | | | | | | | | | | |
| Investment income | | 0.3 |
| | 0.4 |
| | 0.2 |
| |
| Interest expense | | (110.1 | ) | | (107.7 | ) | | (119.8 | ) | | (98.0 | ) | | (110.0 | ) | | (107.4 | ) |
| Charge for early redemption of debt | | (3.3 | ) | | (3.1 | ) | | (2.1 | ) | | (6.5 | ) | | (3.3 | ) | | (3.1 | ) |
| Other income / (expense) | | (0.8 | ) | | 1.0 |
| | 0.2 |
| |
| Other income | | | 0.9 |
| | 1.6 |
| | 3.9 |
|
| Other expense, net | | (113.9 | ) | | (109.4 | ) | | (121.5 | ) | | (103.6 | ) | | (111.7 | ) | | (106.6 | ) |
| | | | | | | | | | | | | |
| Loss from continuing operations before income tax (a) | | $ | (119.9 | ) | | $ | (793.3 | ) | | $ | (231.4 | ) | |
| 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 LossIncome / (loss) from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
DPL – Revenues
Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, our retail sales volume is affected by the number of heating and cooling degree-days occurring during a year. Cooling degree-days typically have a more significant effect than heating degree-days since some residential customers do not use electricity to heat their homes.
Degree-days
| | | | | Years ended December 31, | | Years ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
Heating degree-days (a) | | 4,805 | | 5,034 | | 5,163 | | 5,547 |
| | 4,805 |
| | 5,034 |
|
Cooling degree-days (a) | | 890 | | 1,213 | | 1,060 | | 1,341 |
| | 890 |
| | 1,213 |
|
| |
| (a) | Heating and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree25-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. |
Since we have historically utilized our internal generating capacity to supply the needs of our retail customers within the DP&LDPL's service territory first, increases in on-system retail demand may have decreased the volume of internal generation available to be sold in the wholesale market and vice versa. Beginning in 2016, DP&L retail demand is entirely sourced through a competitive auction. We sell generation into the wholesale market, which covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; retail demand throughout the entire wholesale market area; availability of our generating plants and non-affiliated generating plants to sell into the wholesale market; contracted wholesaleelectric sales and our variable generation costs. Our goal is to make wholesale sales when it is profitable to do so.billed customers were as follows:
The following table provides a summary of changes in revenues from prior periods:
|
| | | | | | | | |
| $ in millions | | 2017 vs. 2016 | | 2016 vs. 2015 |
| Retail | | | | |
| Rate | | $ | (69.2 | ) | | $ | (68.7 | ) |
| Volume | | (28.4 | ) | | 21.0 |
|
| Other | | 0.6 |
| | 1.2 |
|
| Total retail change | | (97.0 | ) | | (46.5 | ) |
| Wholesale | | | | |
| Rate | | (27.6 | ) | | (124.4 | ) |
| Volume | | (67.8 | ) | | 3.9 |
|
| Total wholesale change | | (95.4 | ) | | (120.5 | ) |
| RTO revenues and RTO capacity revenues | | | | |
| RTO revenues and RTO capacity revenues | | 2.1 |
| | (20.7 | ) |
| Other | | | | |
| Other | | (0.1 | ) | | 2.2 |
|
| Total revenue changes | | $ | (190.4 | ) | | $ | (185.5 | ) |
|
| | | | | | | | | |
ELECTRIC SALES AND CUSTOMERS (a) |
| | | DPL |
| | | Years ended December 31, |
| | | 2018 | | 2017 | | 2016 |
Retail electric sales (b) | | 14,439 |
| | 13,863 |
| | 14,499 |
|
Wholesale electric sales (c) | | 1,289 |
| | 816 |
| | 907 |
|
| Total electric sales | | 15,728 |
| | 14,679 |
| | 15,406 |
|
| | | | | | | |
| Billed electric customers (end of period) | | 525,166 |
| | 521,609 |
| | 519,128 |
|
| |
| (a) | Electric sales are presented in millions of KWh. |
| |
| (b) | 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 |
| 20.1 |
|
| | | |
| RTO revenues and RTO capacity revenues | | |
| RTO revenues and RTO capacity revenues | | (1.9 | ) |
| | | |
| Other | | |
| Other revenues | | (1.6 | ) |
| | | |
| Net change in Revenues | | $ | 32.0 |
|
During the year ended December 31, 2017, Revenues decreased $190.4$90.3 million to $1,236.9$743.9 million from $1,427.3$834.2 million in the same period of the prior year. This decrease was primarily the result of lower average retail and wholesale rates and volumes, slightly offset by higher RTO and RTO capacity revenues.
Retail revenues decreased $97.0 million primarily due to an unfavorable $69.2 million retail rate variance and an unfavorable $28.4 million retail volume variance. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016. In addition, there were decreased collections on the USF, competitive bid, and energy efficiency revenue rate riders, as well as a decrease due to the collection of the remaining 2015 deferred fuel balance in the first quarter of 2016. These were partially offset by the implementation of the DMR in November 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree-days decreased by 229 degree-days and cooling degree-days decreased by 323 degree-days.
Wholesale revenues decreased $95.4 million primarily as a result of an unfavorable $67.8 million wholesale volume variance and an unfavorable $27.6 million wholesale rate variance. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in 2017. The decrease in wholesale volumes of $67.8 million was primarily driven by a 13% decrease in internal generation at DPL's plants in 2017 and a decrease in the load served of other parties through their competitive bid process.of:
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, increased $2.1 million compared to the prior year. This increase was the result of a $6.5 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015. This increase was partially offset by a $4.4 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.
During the year ended December 31, 2016, Revenues decreased $185.5 million to $1,427.3 million from $1,612.8 million in the same period of the prior year. This decrease was primarily the result of lower average retail and wholesale rates and lower RTO and RTO capacity revenues, partially offset by higher retail and wholesale volumes.
Retail revenues decreased $46.5 million primarily due to an unfavorable $68.7 million retail rate variance and a favorable $21.0 million retail volume variance. The unfavorable rate variance was due to lower average DP&L retail rates, primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, was lower than the non-auction SSO rate. The decrease was also due to the recovery of deferred storm costs in 2015 and the reversion back to ESP 1 rates in September of 2016, partially offset by $20.1 million of revenue associated with energy efficiency programs recorded in 2016. This decrease in rate was partially offset by a volume increase due to warmer summer weather in 2016 as cooling degree-days increased by 153 along with increased sales to commercial and industrial customers, partially offset by milder winter weather in the first quarter of 2016 as heating degree-days-decreased by 129.
Wholesale revenues decreased $120.5 million as a result of an unfavorable $124.4 million wholesale rate variance and a favorable $3.9 million wholesale volume variance. The unfavorable price variance of $124.4 million was primarily due to lower market prices in 2016 and higher average prices on sales to DPLER in 2015, as DP&L previously had full requirements sales to DPLER in 2015. This price decrease was partially offset by a favorable wholesale volume variance as DP&L had excess generation available to be sold in the wholesale market in 2016 resulting from 100% of its SSO load being served through the competitive bid process compared to 60% during 2015. In addition, there was a 4.5% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the prior year, partially offset by a decrease in volume due to the contract termination with DPLER. As noted above, DP&L previously had full requirements sales to DPLER in 2015. These sales were previously eliminated in consolidation prior to DPLER being accounted for as a discontinued operation.
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and PJM capacity payments, decreased $20.7 million compared to the prior year. This decrease was the result of a $7.7 million decrease in RTO transmission and congestion revenue, as 2015 congestion revenue charges were higher due to milder winter weather in 2016 than 2015. There was also a $13.0 million decrease in revenue realized from the PJM capacity auction in 2016 due to lower capacity cleared and lower prices in both the CP and RPM auctions. The capacity price that became effective in June of 2016 was $134/MW-day, compared to $136/MW-day in June 2015.
|
| | | | |
| $ 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, 2017, Total cost2018, Cost of revenues decreased $136.7increased $22.5 million compared to the prior year. This decreaseincrease was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $58.5 million compared to the same period in the prior year primarily due to a 11% decrease in average fuel cost per MWh and a 13% decrease in internal generation. There were fuel costs deferred in 2015 which were expensed in 2016 because they were collected in 2016, which contributed to the price decrease. The |
| | | | |
| $ 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 | | 25.7 |
|
| Total purchased power change | | 13.5 |
|
| | |
| RTO charges | | 0.3 |
|
| RTO capacity charges | | 0.2 |
|
| Net change in purchased power | | 14.0 |
|
| | | |
| Net change in Cost of Revenues | | $ | 22.5 |
|
decrease in internal generation was primarily due to plant outages, mostly resulting from the January 10, 2017 high pressure feedwater heater shell failure on Unit 1 at the J.M. Stuart station.
Net purchased power decreased $78.2 million compared to the prior year. This decrease was driven by the following factors:
| |
◦ | Purchased power decreased $66.5 million primarily due to a $32.4 million volume decrease and a $34.1 million price decrease compared to the same period in the prior year. The volume decrease was primarily driven by a lower load served through the competitive bid process of other parties compared to 2016, as well as the decrease in DP&L retail demand in 2017. The price decrease was primarily driven by lower rates in the competitive bid process in 2017 compared to 2016.
|
| |
◦ | RTO charges decreased $7.7 million compared to the prior year primarily due to lower transmission and congestion charges. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network, which are incurred and charged to customers in the transmission rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.
|
| |
◦ | RTO capacity charges decreased $6.6 million compared to the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction.
|
| |
◦ | Mark-to-market gains decreased $2.6 million due to changes in power prices in 2017 and 2016. |
During the year ended December 31, 2016, Total cost2017, Cost of revenues decreased $136.2 million compared to the prior year. This decrease was a result of:
Net fuel costs increased $9.0 million compared to the prior year primarily due to a 7.2% increase in internal generation, partially offset by a 2.4% decrease in average fuel cost per MWh.
Net purchased power decreased $145.2 million compared to the prior year. This decrease was driven by the following factors:
| |
◦ | Purchased power decreased $14.1 million primarily due to a $55.4 million volume decrease as DP&L no longer purchased power to source DPLER customers due to the sale of DPLER on January 1, 2016. This volume decrease was partially offset by increased purchases as DP&L sourced 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DPL purchases power for the SSO load sourced through the competitive bid process and to serve auction load requirements in service territories other than DP&L's. The decrease in volume was also offset by an unfavorable price variance of $41.3 million driven by higher prices in the competitive bid process.
|
| |
◦ | RTO charges decreased $19.5 million primarily as a result of no longer having a DP&L retail load obligation as a result of 100% SSO sales being sourced through the competitive auction. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within our network which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on DP&L's wholesale revenues, and costs associated with load obligations for retail customers.
|
| |
◦ | RTO capacity charges decreased $101.2 million primarily due to DP&L no longer having a retail load requirement in 2016, resulting from the SSO load being 100% sourced through competitive bid in 2016 as opposed to 60% in 2015 and, additionally, from the fact that DP&L did not provide power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction.
|
| |
◦ | Mark-to-market losses decreased $10.4 million due to less significant decreases in power prices in 2016, resulting in gains on derivative forward power purchase contracts. |
DPL - Operation and Maintenance
During the year ended December 31, 2017, Operation and Maintenance expense decreased $20.5$36.5 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) | | $ | (23.4 | ) |
| Decrease in generating facilities operating and maintenance expenses | | (9.5 | ) |
Decrease in alternative energy and energy efficiency programs (a) | | (8.4 | ) |
| Increase in group insurance expense associated with participation in the AES self-insurance plan | | 8.6 |
|
| Increase in severance costs due to announced plant closures and restructuring | | 6.8 |
|
| Increase in legal and other consulting costs | | 3.5 |
|
| Increase in retirement benefits costs | | 3.3 |
|
| Other, net | | (1.4 | ) |
| Net change in Operations and Maintenance expense | | $ | (20.5 | ) |
|
| | | | |
| $ 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 thisthese program costs resulting in minimal impact to Net income. |
During the year ended December 31, 2016,2017, Operation and Maintenance expense decreased $13.2$27.4 million compared to the prior year. This decrease was a result of:
|
| | | | |
| $ in millions | | 2016 vs. 2015 |
Decrease in deferred storm costs as they were recognized in 2015 due to their recovery through customer rates (a) | | $ | (17.5 | ) |
| Decrease in generating facilities operating and maintenance expenses | | (13.0 | ) |
| Decrease in expenses due to the reversal of the Economic Development Fund, resulting from the withdrawal of ESP 2 | | (3.0 | ) |
| Decrease in group insurance, associated with the participation in the AES self-insurance plan, and long-term disability expenses | | (2.5 | ) |
Increase in alternative energy and energy efficiency programs (a) | | 13.2 |
|
Increase in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a) | | 6.2 |
|
| Increase in retirement benefits costs | | 1.8 |
|
| Increase in property insurance | | 1.5 |
|
| Other, net | | 0.1 |
|
| Net change in Operation and Maintenance expense | | $ | (13.2 | ) |
|
| | | | |
| $ 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 thisthese 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 decreased $25.4increased $2.5 million compared to the prior year. The decreaseincrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016, and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fortadditional investments in transmission and Zimmer depreciation expense due to the sale of these two plants.distribution fixed assets.
During the year ended December 31, 2016, Depreciation and amortization expense decreased $2.3 million compared to the prior year. The decrease was primarily a result of the fixed asset impairment in Q2 of 2016, which reduced depreciation expense due to the lower asset values.
DPL – General Taxes
During the year ended December 31, 2017,2018, General taxes increased $4.0decreased $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 $1.6$2.4 million favorable true-up of the 2015 Ohio property tax accrual recorded in 2016 to reflect actual payments made in 2016, combined with an unfavorable true-up of $1.2$1.1 million recorded in 2017 for the 2016 Ohio property tax accrual to reflect actual payments made in 2017 and a $0.7$1.4 million reserve recordedincrease in 2017 for a potential property tax settlement.
During the year ended December 31, 2016, General taxes decreased $1.3 million compared to the prior year.
DPL – Goodwill Impairment
During the year ended December 31, 2015, DPL recorded an impairment of goodwill of $317.0 million, which was a full impairment of the remaining goodwill balance. The goodwill impairment test indicated that the fair value of the DP&L Reporting Unit was less than its carrying amount, primarily due to a decrease in dark spreads that were driven by decreases in forward power prices, and lower revenues from the new CP product. See Note 7 – Goodwill of Notes to DPL’s Consolidated Financial Statements.other general taxes.
DPL – Fixed-asset Impairments
During the year ended December 31, 2017,2018, DPL recorded impairmentsan impairment of fixed assets totaling $175.8 million. In the first quarter of 2017, the Board of Directors of DP&L approved the retirement of the then DP&L operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. DPL performed a long-lived asset impairment analysis and$2.8 million for Conesville, as it was determined that theits carrying amounts of the Facilities wereamount was not recoverable. As a result, DPL recognized asset impairment expense of $66.4 million in the first quarter of 2017. In the fourth quarter of 2017, DPL signed an agreement with Kimura Power, LLC for the sale of its Peaker assets. Because the Peaker assets met the criteria to be classified as held-for-sale and the carrying value of the Peaker assets exceeded the fair value less cost to sell as of December 31, 2017, DPL recognized asset impairment expense of $109.4 million in fourth quarter of 2017.
During the year ended December 31, 2016, DPL recorded impairmentsan impairment of fixed assets totaling $859.0of $23.9 million. In the second quarter of 2016, DPL recorded a $235.5 million fixed-asset impairment as DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of Killen and certain DP&L peaking generating facilities were not recoverable. In the fourth quarter of 2016, DPL recorded an additional $623.5 million fixed asset impairment as DP&Lperformed a long-lived asset impairment analysis for the Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups, as well as the Hutchings gas-fired peaking plant asset group and determined that theirits carrying amounts wereamount was not recoverable.
DPL – Loss on Disposal of Business
During the year ended December 31, 2015,2018, DPL did not record any impairmentsrecorded a loss on disposal of fixed assets.
For more informationbusiness of $11.7 million due to the loss on these impairments, see Note 15 – Fixed-asset Impairmentsthe transfer of Notes to DPL's Consolidated Financial Statements.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 $2.4$2.6 million compared to the prior year primarily due to higher interest rates. On August 24, 2016, DP&Lrefinanced 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%.
During the year ended December 31, 2016, Interest expense decreased $12.1 million compared to the prior year primarily due to debt repayments at DPL and DP&L, as well as a $3.8 million decrease in carrying costs primarily related to the recovery of deferred storm costs in 2015.
DPL – Charge for Early Redemption of Debt
During the year ended December 31, 2017,2018, DPLrecorded 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 and associated write-off of deferred financing costs.2036.
During the year ended December 31, 2016, DPL recorded a charge for early redemption of debt
$3.1 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.
During the year ended December 31, 2015, DPL recorded a charge for early redemption of debt of $2.1 million primarily due to the write off of deferred financing costs associated with the refinancing of its revolving credit facility and its term loan.
DPL – Other
During the year ended December 31, 2017, DPL recorded Other operating income of $6.6 million primarily consisting of the $14.0 million gain on sale of the Miami Fort and Zimmer plants and $8.7 million of insurance
recoveries, partially offset by the $16.2 million write-off of plant materials and supplies inventory at the Stuart and Killen plants.
During the year ended December 31, 2016, DPL recorded Other operating income of $0.1 million.
During the year ended December 31, 2015, DPL recorded Other operating expense of $0.4 million.
DPL – Income Tax Expense
During the year ended December 31, 2017, Income tax benefit decreased $253.5of $5.0 million comparedin 2017 changed to expense of $0.7 million in 2018. This change was primarily driven by the prior year primarily due to lower pre-tax lossincrease 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 the prior yearpre-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 yearyears ended December 31, 2018, 2017 and 2016, Income tax benefit increased $298.8DPL recorded income / (loss) from discontinued operations (net of tax) of $38.9 million, compared$(93.1) million and $(500.0) million, respectively. This income / (loss) relates to the prior year primarily due to a pre-tax lossgeneration 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 current year and the recording of a goodwill impairment, which is not deductible for income tax purposes, in 2015 that did not occur in 2016. This was partially offset by an increaseNotes to income tax expense due to non-taxable depreciation of AFUDC equity.DPL's Consolidated Financial Statements.
RESULTS OF OPERATIONS BY SEGMENT – DPL Inc.
Beginning with the second quarter of 2018, DPL currentlyhas 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 twoonly one reportable operating segments,segment, the T&D segment and the GenerationUtility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The segments areUtility segment is discussed further below:
Transmission and DistributionUtility Segment
The T&DUtility 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 521,000525,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&DUtility segment includes revenues and costs associated with DP&L'sour 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 Coal generating facilities,EGU, which were eitherwas closed or sold in prior periods. As these2013. These assets weredid not transferredtransfer to AES Ohio Generation as part of DP&L's Generation Separation on October 1, 2017. Thus, they are grouped withwithin the T&D assetsUtility segment for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&DUtility segment.
Generation Segment
The Generation segment is comprised of AES Ohio Generation and the historical results of DP&L's electric generation business prior to Generation Separation. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates coal-fired and peaking generating facilities and sells its generated energy and capacity into the PJM wholesale market. The 2015 Generation segment results also include sales to DPLER and to the T&D segment for SSO customers.
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 1413 – Business Segments of Notes to DPL’sDPL's Consolidated Financial Statements for additional information regarding DPL’s reportable segments.segment.
The following table presents DPL’s LossIncome / (loss) from continuing operations before income tax by business segment:
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 |
| T&D | | $ | 88.5 |
| | $ | 143.0 |
| | $ | 188.1 |
|
| Generation | | (18.5 | ) | | (1,353.9 | ) | | (28.7 | ) |
| Other | | (189.9 | ) | | 417.6 |
| | (390.8 | ) |
| Loss from continuing operations before income tax | | $ | (119.9 | ) | | $ | (793.3 | ) | | $ | (231.4 | ) |
|
| | | | | | | | | | | | |
| | | 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 – T&DUtility Segment
The results of operations of the T&DUtility segment for DPL are identical in all material respects and for all periods presented to those of DP&L results from continuing operations, 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.
Statement of Operations Highlights - DPL – Generation Segment
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 |
| Revenues: | | | | | | |
| Retail | | $ | 0.3 |
| | $ | 0.3 |
| | $ | 0.4 |
|
| Wholesale | | 359.5 |
| | 463.6 |
| | 786.8 |
|
| RTO revenue | | 10.8 |
| | 16.7 |
| | 24.8 |
|
| RTO capacity revenues | | 137.3 |
| | 131.0 |
| | 144.8 |
|
| Mark-to-market gains / (losses) | | — |
| | (0.1 | ) | | 0.1 |
|
| Total revenues | | 507.9 |
| | 611.5 |
| | 956.9 |
|
| | | | | | | |
| Cost of revenues: | | | | | | |
| Fuel cost: | | | | | | |
| Fuel | | 211.1 |
| | 269.8 |
| | 272.1 |
|
| Gains from sale of coal | | (1.3 | ) | | (6.3 | ) | | (3.0 | ) |
| Mark-to-market gains | | — |
| | — |
| | (0.3 | ) |
| Net fuel cost | | 209.8 |
| | 263.5 |
| | 268.8 |
|
| | | | | | | |
| Purchased power: | | | | | | |
| Purchased power | | 24.1 |
| | 63.7 |
| | 303.8 |
|
| RTO charges | | 13.5 |
| | 19.8 |
| | 40.3 |
|
| RTO capacity charges | | 12.7 |
| | 21.5 |
| | 103.3 |
|
| Mark-to-market losses / (gains) | | (1.7 | ) | | (4.4 | ) | | 6.1 |
|
| Net purchased power cost | | 48.6 |
| | 100.6 |
| | 453.5 |
|
| | | | | | | |
| Total cost of revenues | | 258.4 |
| | 364.1 |
| | 722.3 |
|
| | | | | | | |
| Gross margin | | 249.5 |
| | 247.4 |
| | 234.6 |
|
| | | | | | | |
| Operating expenses: | | | | | | |
| Operation and maintenance | | 172.5 |
| | 174.7 |
| | 171.3 |
|
| Depreciation and amortization | | 20.9 |
| | 55.4 |
| | 72.6 |
|
| General taxes | | 13.2 |
| | 17.6 |
| | 16.0 |
|
| Fixed-asset impairment | | 66.3 |
| | 1,353.5 |
| | — |
|
| Other, net | | (5.0 | ) | | 0.3 |
| | 0.3 |
|
| Total operating expenses | | 267.9 |
| | 1,601.5 |
| | 260.2 |
|
| | | | | | | |
| Operating loss | | (18.4 | ) | | (1,354.1 | ) | | (25.6 | ) |
| | | | | | | |
| Other income / (expense), net | | | | | | |
| Interest expense | | (0.1 | ) | | (0.4 | ) | | (2.9 | ) |
| Charge for early redemption of debt | | — |
| | — |
| | (0.2 | ) |
| Other income | | — |
| | 0.6 |
| | — |
|
| Total other income / (expense), net | | (0.1 | ) | | 0.2 |
| | (3.1 | ) |
| | | | | | | |
| Loss from continuing operations before income tax (a) | | $ | (18.5 | ) | | $ | (1,353.9 | ) | | $ | (28.7 | ) |
| |
(a) | For purposes of discussing operating results, we present and discuss Loss from continuing operations before income tax. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance. |
DPL – Generation Segment – Revenues
During the year ended December 31, 2017, the segment’s revenues decreased $103.6 million to $507.9 million from $611.5 million in the prior year. This decrease was primarily the result of lower average wholesale rates, lower wholesale volumes, and lower RTO revenues, partially offset by increased RTO capacity revenues.
Wholesale revenues decreased $104.1 million primarily as a result of an unfavorable wholesale volume variance of $81.3 million and an unfavorable wholesale price variance of $22.8 million. Despite increases in PJM market prices, the unfavorable price variance was due to lower realized gains on derivatives in
2017. The decrease in wholesale volumes was primarily driven by a 13% decrease in internal generation at DPL's plants in 2017 and a decrease in the load served of other parties through their competitive bid process.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, increased $0.4 million compared to the prior year primarily due to a $6.3 million increase in revenue realized from the PJM capacity auction in 2017 primarily due to higher average prices in the CP auction. The capacity price that became effective in June of 2017 was $152/MW-day, compared to $59/MW-day under the base RPM auction and $134/MW-day for the transitional CP auction in June of 2016, and $136/MW-day in June of 2015. This increase was partially offset by a $5.9 million decrease in RTO revenues due to lower rates and availability related to compensation for DPL's reactive supply and operating reserves.
During the year ended December 31, 2016, the segment’s revenues decreased $345.4 million to $611.5 million from $956.9 million in the prior year. This decrease was primarily the result of lower average wholesale rates, the sale of DPLER in 2016, and lower RTO capacity and other revenues, partially offset by increased wholesale volume.
Wholesale revenues decreased $323.2 million primarily as a result of the 2016 sale of DPLER, which accounted for $304.8 million of wholesale sales in 2015. DP&L had full requirements sales to DPLER in 2015 until the competitive retail business was sold on January 1, 2016. The remaining decrease of $18.4 million was primarily due to lower market prices in 2016, partially offset by a 4.5% increase in internal generation from DP&L's co-owned and operated plants in 2016 compared to the prior year.
RTO capacity and other revenues, consisting primarily of PJM capacity revenues, regulation services, reactive supply and operating reserves, decreased $21.9 million compared to the prior year. RTO transmission and congestion revenue decreased $8.1 million as 2015 congestion revenue charges were higher due to milder winter weather in 2016 than 2015. In addition, revenue realized from the PJM capacity auction decreased $13.8 million in 2016 due to lower capacity cleared and lower price in both the CP and RPM auctions. The capacity price that became effective in June 2016 was $134/MW-day compared to $136/MW-day in June 2015.
DPL – Generation Segment – Cost of Revenues
During the year ended December 31, 2017, Total cost of revenues decreased $105.7 million compared to the prior year. This decrease was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $53.7 million compared to the prior year primarily due to a 11% decrease in average fuel cost per MWh and a 13% decrease in internal generation.
Net purchased power decreased $52.0 million compared to the prior year. This decrease was driven by the following factors:
| |
◦ | Purchased power decreased $39.6 million primarily due to a favorable volume variance of $28.7 million and a favorable price variance of $10.9 million. The decrease in volume was driven by a lower load served of other parties through their competitive bid process in 2017. Despite increases in PJM market prices, the favorable price variance was due to lower realized losses on derivatives in 2017. The generation segment purchases power to source retail load in other service territories and to meet contracted Wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.
|
| |
◦ | RTO charges decreased $6.3 million compared to the prior year primarily due to lower transmission and congestion charges. |
| |
◦ | RTO capacity charges decreased $8.8 million compared to the prior year primarily due to a lower retail load served in 2017, as well as a $1.7 million PJM penalty incurred in March 2016 associated with low plant availability. Retail load served relates to the load of other parties through their competitive bid process. As noted above, RTO capacity prices are set by an annual auction. |
| |
◦ | Mark-to-market gains decreased $2.7 million due to changes in power prices in 2017 and 2016. |
During the year ended December 31, 2016, Total cost of revenues decreased $358.2 million compared to the prior year. This decrease was a result of:
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $5.3 million compared to the prior year primarily due to a 7.5% decrease in average fuel cost per MWh and a $3.3 million decrease in gains on the sale of coal, partially offset by a 7.2% increase in internal generation.
Net purchased power decreased $352.9 million compared to the prior year. This decrease was driven by the following factors:
| |
◦ | Purchased power decreased $240.1 million primarily due to decreased power purchased to source DPLER customers, as DP&L previously had full requirements sales to DPLER in 2015. We purchase power to source retail load in other service territories and to source DPLER customers in 2015. The generation segment also purchases power to meet contracted Wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.
|
| |
◦ | RTO charges decreased $20.5 million primarily as a result of no longer having load obligations on sales to DPLER. RTO charges are incurred as a member of PJM and include costs associated with the segment's load obligations and transmission and congestion losses incurred on the segments wholesale revenues. |
| |
◦ | RTO capacity charges decreased $81.8 million primarily due to the segment no longer providing power to DPLER in 2016. The remaining charges primarily relate to serving the load of other parties through their competitive bid process. As noted in the revenue section above, RTO capacity prices are set by an annual auction. |
| |
◦ | Mark-to-market gains increased $10.5 million due to less significant decreases in power prices in 2016 causing gains on derivative forward power purchase contracts. |
DPL – Generation Segment – Operation and Maintenance
During the year ended December 31, 2017, Operation and Maintenance expense decreased $2.2 million compared to the prior year. This decrease was a result of:
|
| | | | |
| $ in millions | | 2017 vs. 2016 |
| Decrease in generating facilities operating and maintenance expenses | | (9.6 | ) |
| Decrease in insurance and claims reserve | | (2.5 | ) |
| Increase in severance costs due to announced plant closures and restructuring | | 6.8 |
|
| Increase in group insurance expense associated with participation in the AES self-insurance plan | | 4.5 |
|
| Other, net | | (1.4 | ) |
| Net change in Operations and Maintenance expense | | $ | (2.2 | ) |
During the year ended December 31, 2016, Operation and Maintenance expense increased $3.4 million compared to the prior year. This increase was a result of:
|
| | | | |
| $ in millions | | 2016 vs. 2015 |
| Increase in insurance and claims reserve due to insurance proceeds received from MVIC in 2015 | | 6.5 |
|
| Increase in retirement benefits costs | | 4.3 |
|
| Increase in legal and other consulting fees | | 2.4 |
|
| Decrease in generating facilities operating and maintenance expenses | | (12.0 | ) |
| Other, net | | 2.2 |
|
| Net change in Operation and Maintenance expense | | $ | 3.4 |
|
DPL – Generation Segment – Depreciation and Amortization
During the year ended December 31, 2017, Depreciation and amortization expense decreased $34.5 million compared to the prior year. The decrease was primarily a result of the fixed-asset impairments in the second and fourth quarters of 2016, and the first quarter of 2017, which reduced depreciation expense due to the lower asset values. In addition, the decrease was attributable to the discontinuation of Miami Fort and Zimmer depreciation expense due to the sale of these two plants.
During the year ended December 31, 2016, Depreciation and amortization expense decreased $17.2 million compared to the prior year. The decrease was primarily a result of the fixed-asset impairment in the second quarter of 2016, which reduced depreciation expense due to the lower asset values.
DPL – Generation Segment – General Taxes
During the year ended December 31, 2017, General taxes decreased $4.4 million compared to the prior year. The decrease was primarily the result of a $3.0 million reduction in 2017 expense due to a true-up of the year to date 2017 Ohio property tax accrual to reflect final assessments for 2017 taxes and an unfavorable $0.9 million true-up of the 2015 Ohio property tax accrual to reflect actual payments made in 2016.
During the year ended December 31, 2016, General taxes increased $1.6 million compared to the prior year.
DPL – Generation Segment – Fixed-asset Impairments
During the year ended December 31, 2017, the Generation segment recorded fixed-asset impairments, without the effect of the purchase accounting adjustments included in the Other column of segments, of $66.3 million. In the first quarter of 2017, the Board of Directors of DP&L approved the retirement of the then DP&L-operated and co-owned Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine (collectively, the “Facilities”) on or before June 1, 2018. The co-owners of these facilities agreed with DP&L to proceed with this plan of retirement. DPL performed a long-lived asset impairment analysis and determined that the carrying amounts of the Facilities were not recoverable. As a result, DPL's Generation segment recognized asset impairment expense of $66.3 million in the first quarter of 2017. Because the Peaker asset impairment expense was included with purchase accounting adjustments in the Other column of segments, DPL's Generation segment did not record a fixed-asset impairment related to the Peaker assets in 2017.
During the year ended December 31, 2016, DPL's Generation segment recorded fixed-asset impairments, without the effect of the purchase accounting adjustments included in the Other column of segments, of $1,353.5 million. In the second quarter of 2016, the Generation segment recorded an $857.1 million fixed-asset impairment, as DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups of then DP&L-operated Killen and certain peaking generating facilities were not recoverable. In the fourth quarter of 2016, the Generation segment recorded an additional $496.4 million fixed-asset impairment as DP&L performed a long-lived asset impairment analysis for the then DP&L-operated Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groups, as well as the Hutchings gas-fired peaking plant asset group and determined that their carrying amounts were not recoverable.
For more information on these impairments, see Note 15 – Fixed-asset Impairments of Notes to DPL's Consolidated Financial Statements.
DPL – Generation Segment – Interest Expense
During the year ended December 31, 2017, Interest expense decreased $0.3 million.
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. Prior to Generation Separation on October 1, 2017, for segment purposes, $750.0 million of debt and the pro rata interest expense associated with that debt were allocated to the T&D segment. All remaining debt and interest expense were included in the Generation segment.
During the year ended December 31, 2016, Interest expense decreased $2.5 million compared to the prior year due primarily to a reduction of debt.
RESULTS OF OPERATIONS – DP&L
Statement of Operations Highlights – DP&L
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Revenues: | | | | | | | | | | | | |
| Retail | | $ | 642.6 |
| | $ | 739.8 |
| | $ | 786.4 |
| | $ | 657.9 |
| | $ | 642.6 |
| | $ | 739.8 |
|
| Wholesale | | 23.6 |
| | 16.1 |
| | 19.7 |
| | 29.9 |
| | 23.6 |
| | 16.1 |
|
| RTO revenue | | 47.2 |
| | 45.7 |
| | 45.3 |
| | 43.1 |
| | 47.2 |
| | 45.7 |
|
| RTO capacity revenues | | 6.6 |
| | 6.4 |
| | 5.6 |
| | 7.8 |
| | 6.6 |
| | 6.4 |
|
| Total revenues | | 720.0 |
| | 808.0 |
| | 857.0 |
| | 738.7 |
| | 720.0 |
| | 808.0 |
|
| | | | | | | | |
| Cost of revenues: | | | | | | | | | | | | |
| | | | | | | | |
| Net fuel cost | | 0.5 |
| | 5.3 |
| | (9.0 | ) | | 2.4 |
| | 0.5 |
| | 5.3 |
|
| | | | | | | | |
| Purchased power: | | | | | | | | | | | | |
| Purchased power | | 230.6 |
| | 258.3 |
| | 238.1 |
| | 243.5 |
| | 230.6 |
| | 258.3 |
|
| RTO charges | | 57.2 |
| | 58.6 |
| | 60.1 |
| | 55.6 |
| | 57.2 |
| | 58.6 |
|
| RTO capacity charges | | 2.0 |
| | (0.2 | ) | | 19.2 |
| | 2.2 |
| | 2.0 |
| | (0.2 | ) |
| Net purchased power cost | | 289.8 |
| | 316.7 |
| | 317.4 |
| | 301.3 |
| | 289.8 |
| | 316.7 |
|
| | | | | | | | |
| Total cost of revenues | | 290.3 |
| | 322.0 |
| | 308.4 |
| | 303.7 |
| | 290.3 |
| | 322.0 |
|
| | | | | | | | | | | | | |
| Gross margin | | 429.7 |
| | 486.0 |
| | 548.6 |
| | 435.0 |
| | 429.7 |
| | 486.0 |
|
| | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | |
| Operation and maintenance | | 158.0 |
| | 179.3 |
| | 184.0 |
| | 139.7 |
| | 156.5 |
| | 178.4 |
|
| Depreciation and amortization | | 75.3 |
| | 71.0 |
| | 71.5 |
| | 74.5 |
| | 75.3 |
| | 71.0 |
|
| General taxes | | 76.3 |
| | 68.0 |
| | 70.8 |
| | 73.1 |
| | 76.3 |
| | 68.0 |
|
| Other, net | | (0.5 | ) | | (0.4 | ) | | 0.1 |
| |
| Loss / (gain) on asset disposal | | | 0.2 |
| | (0.5 | ) | | (0.4 | ) |
| Loss on disposal of business (Note 15) | | | 12.4 |
| | — |
| | — |
|
| Total operating expenses | | 309.1 |
| | 317.9 |
| | 326.4 |
| | 299.9 |
| | 307.6 |
| | 317.0 |
|
| | | | | | | | | | | | | |
| Operating income | | 120.6 |
| | 168.1 |
| | 222.2 |
| | 135.1 |
| | 122.1 |
| | 169.0 |
|
| | | | | | | | | | | | | |
| Other expense, net | | | | | | | | | | | | |
| Investment income | | 0.3 |
| | 0.4 |
| | 0.3 |
| |
| Interest expense | | (30.5 | ) | | (24.7 | ) | | (28.9 | ) | | (27.3 | ) | | (30.5 | ) | | (24.7 | ) |
| Charge for early redemption of debt | | (1.1 | ) | | (0.5 | ) | | (4.8 | ) | | (0.6 | ) | | (1.1 | ) | | (0.5 | ) |
| Other income / (expense) | | (0.8 | ) | | 0.3 |
| | 0.2 |
| |
| Other income | | | (2.8 | ) | | (2.0 | ) | | (0.2 | ) |
| Total other expense, net | | (32.1 | ) | | (24.5 | ) | | (33.2 | ) | | (30.7 | ) | | (33.6 | ) | | (25.4 | ) |
| | | | | | | | | | | | | |
| Income from continuing operations before income tax (a) | | $ | 88.5 |
| | $ | 143.6 |
| | $ | 189.0 |
| | $ | 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:
|
| | | | | | | | | |
ELECTRIC SALES AND CUSTOMERS (a) |
| | | DP&L |
| | | Years ended December 31, |
| | | 2018 | | 2017 | | 2016 |
Retail electric sales (b) | | 14,439 |
| | 13,863 |
| | 14,499 |
|
Wholesale electric sales (c) | | 755 |
| | 538 |
| | 509 |
|
| Total electric sales | | 15,194 |
| | 14,401 |
| | 15,008 |
|
| | | | | | | |
| Billed electric customers (end of period) | | 525,166 |
| | 521,609 |
| | 519,128 |
|
| |
| (a) | Electric sales are presented in millions of KWh. |
| |
| (b) | 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. |
DP&L – Revenues
The following table providesDuring 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 summary of changes in DP&L’s Revenues from prior periods:result of:
| | | $ in millions | | 2017 vs. 2016 | | 2016 vs. 2015 | | 2018 vs. 2017 |
| Retail | | | | | | |
| Rate | | $ | (69.3 | ) | | $ | (68.7 | ) | |
|
|
| 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 | | (28.5 | ) | | 21.0 |
| | |
| Other | | 0.6 |
| | 1.1 |
| |
| 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 | | (97.2 | ) | | (46.6 | ) | | 15.3 |
|
| | | | |
| Wholesale | | | | | | |
| Wholesale revenues | | 7.5 |
| | (3.6 | ) | | |
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 | | 1.7 |
| | 1.2 |
| | (2.9 | ) |
| Total revenues change | | $ | (88.0 | ) | | $ | (49.0 | ) | |
| | | | |
| 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 prior year. This decrease was primarily the resultsame period of lower average retail rates and lower retail volumes, partially offset by higher wholesale, RTO capacity and other revenues.
Retail revenues decreased $97.2 million primarily due to an unfavorable $69.3 million retail rate variance and an unfavorable $28.5 million retail volume variance. The decrease in average retail rates was primarily driven by reverting to ESP 1 rates in September of 2016. In addition, there were decreased collections on the USF, competitive bid, and energy efficiency revenue rate riders, as well as a decrease due to the collection of the remaining 2015 deferred fuel balance in the first quarter of 2016. These were partially offset by the implementation of the DMR in November 2017. The decrease in retail volume was primarily driven by more mild weather in 2017, as heating degree-days decreased by 229 degree-days and cooling degree-days decreased by 323 degree-days. In addition, there was a favorable other miscellaneous variance of $0.6 million.
Wholesale revenues increased $7.5 million. These revenues consist of DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at market prices.
RTO capacity and other revenues increased $1.7 million compared to the prior year.
During the year ended December 31, 2016, Revenues decreased $49.0 million to $808.0 million from $857.0 million in the prior year. This decrease was primarily thea result of lower average retail rates, partially offset by higher retail volumes, higher wholesale revenues, and higher RTO revenues.of:
Retail revenues decreased $46.6 million primarily due to an unfavorable $68.7 million retail rate variance and a favorable $21.0 million retail volume variance. The unfavorable rate variance was due to lower average DP&L retail rates, primarily driven by decreased retail revenue from SSO customers as the competitive auction rate, which represents 100% of DP&L SSO load in 2016 compared to 60% in 2015, was lower than the non-auction SSO rate. The decrease was also due to the recovery of deferred storm costs in 2015 and the reversion back to ESP 1 rates in September of 2016, partially offset by $20.1 million of revenue associated with energy efficiency programs recorded in 2016. This decrease in rate was partially offset by a volume increase due to warmer summer weather in 2016 as cooling degree-days increased by 153 along with increased sales to commercial and industrial customers, partially offset by milder winter weather in the first quarter of 2016 as heating degree-days decreased by 129.
Wholesale revenues decreased $3.6 million. These revenues consisted of DP&L's 4.9% share of the generation output of OVEC, which is sold into PJM at market prices.
|
| | | | |
| $ 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 | | 7.5 |
|
| | | |
| RTO revenues and RTO capacity revenues | | |
| RTO revenues and RTO capacity revenues | | 1.7 |
|
| | | |
| Net change in Revenues | | $ | (88.0 | ) |
RTO capacity and other revenues increased $1.2 million compared to the prior year.
DP&L – Cost of Revenues
During the year ended December 31, 2017, total cost of revenues decreased $31.7 million compared to the prior year. This decrease was primarily due to:
Net fuel costs, which include expense recognition or deferral coinciding with the collection of fuel costs through the regulatory fuel deferral, decreased $4.8 million compared to the prior year primarily due to fuel costs deferred in 2015, being collected in 2016. There was only $0.5 million of previously deferred fuel costs collected in 2017.
Net purchased power decreased $26.9 million compared to the prior year. This decrease was driven by the following factors:
| |
◦ | Purchased power decreased $27.7 million compared to the prior year primarily due to a favorable price variance of $19.8 million driven by lower rates in the competitive bid process in 2017, and lower volumes of $7.9 million primarily due to the decrease in DP&L retail demand in 2017.
|
| |
◦ | RTO capacity and other charges increased $0.8 million compared to the prior year. |
During the year ended December 31, 2016, total cost2018, Cost of revenues increased $13.6$13.4 million compared to the prior year. This increase was primarily due to:a result of:
Net fuel costs, which include expense recognition or deferral coinciding with the collection of fuel costs through the regulatory fuel deferral, increased $14.3 million compared to the prior year primarily due to fuel costs deferred in 2015, being collected in 2016.Net purchased power decreased $0.7 million compared to the prior year. This decrease was driven by the following factors: |
| | | | |
| $ 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 |
|
| |
◦ | Purchased power increased $20.2 million primarily due to an unfavorable price variance driven by prices in the competitive bid process. DP&L sourced 100% of SSO load through the competitive bid process in 2016 as opposed to 60% in 2015. DP&L purchases power for its SSO load.
|
| |
◦ | RTO capacity and other charges decreased $20.9 million driven by decreased load obligations for retail customers as DP&L's retail load fully transitioned to market and was fully sourced through the competitive bid process in 2016. RTO charges are incurred by DP&L as a member of PJM and primarily include transmission charges within DP&L's network, which are incurred and charged to customers in the TCRR-N rider, transmission and congestion losses incurred on revenues, and costs associated with load obligations for retail customers.
|
DP&L – Operation and Maintenance
During the year ended December 31, 2017, Operation and Maintenance expenseCost of revenues decreased $21.3$31.7 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) | | $ | (23.4 | ) |
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 Operations and Maintenance expense | | $ | (21.3 | ) |
|
| | | | |
| $ 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 thisthese program costs resulting in minimal impact to Net income. |
During the year ended December 31, 2016,2017, Operation and Maintenance expense decreased $4.7$21.9 million compared to the prior year. This decrease was a result of:
|
| | | | |
| $ in millions | | 2016 vs. 2015 |
Decrease in deferred storm costs as they were recognized in 2015 due to their recovery through customer rates (a) | | $ | (17.5 | ) |
| Decrease in expenses due to the reversal of the Economic Development Fund, resulting from the withdrawal of ESP 2 | | (3.0 | ) |
| Decrease in generating facilities operating and maintenance expenses, primarily due the sale of East Bend and closure of Beckjord in 2014 | | (2.7 | ) |
| Decrease in retirement benefits costs | | (1.5 | ) |
Increase in alternative energy and energy efficiency programs (a) | | 13.2 |
|
Increase in uncollectible expenses for the low-income payment program, which is funded by the USF revenue rate rider (a) | | 6.2 |
|
| Other, net | | 0.6 |
|
| Net change in Operation and Maintenance expense | | $ | (4.7 | ) |
|
| | | | |
| $ 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. The increaseThis change was primarily due to additional investments in transmission and distribution fixed assets.
DP&L – General Taxes
During the year ended December 31, 2016, Depreciation and amortization expense2018, General taxes decreased $0.5$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.
DP&L – General Taxes
During the year ended December 31, 2017, General taxes increased $8.3 million compared to the prior year.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, 2016, General taxes decreased $2.82018, DP&L recorded a Loss on disposal of business of $12.4 million compareddue to the prior year primarily due to a $2.4 million favorable true-uploss on the transfer of business interests in the 2015 property tax accrual to reflect actual payments made in 2016 and a $0.6 million unfavorable true-up of the 2014 property tax accrual to reflect actual payments made in 2015.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&Lrefinanced 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%.
During the year ended December 31, 2016, interest expense decreased $4.2 million compared to the prior year primarily due to a decrease in carrying costs related to the recovery of deferred storm costs in 2015. 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. For DP&L purposes in 2016 and 2015, $750.0 million of debt and the pro rata interest expense associated with that debt has been allocated to DP&L continuing operations.
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
$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.
During the year ended December 31, 2015, DPL recorded a charge for early redemption of debt of $4.8 million primarily due to the write off of deferred financing costs associated with the refinancing of its revolving credit facility.
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 comparedfrom $46.0 million in 2016 to the prior year$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.
During the year ended December 31, 2016, Income tax expense decreased $13.0 million compared to the prior year primarily due to a decrease in pre-tax income and a deferred tax adjustment that did not occur in 2015. Partially offsetting the decrease was an increase in the depreciation of AFUDC Equity and the addition of a tax reserve for the amended 2011 predecessor tax return refund claim.
DP&L - Discontinued Operations
During the years ended December 31, 2017 2016, and 2015,2016, DP&L recorded losses from discontinued operations (net of tax) of $40.4 million $870.3 million and $23.6$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 13 -14 – Generation Separation in Notes to DP&L's Consolidated Financial Statements.
KEY TRENDS AND UNCERTAINTIES
DuringFollowing the issuance of the DRO in September 2018 and beyond,the resulting changes to the decoupling rider effective January 1, 2019, we expect that our financial results will no longer be driven primarily by retail demand and weather energy efficiencybut 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 wholesale prices on financial results.Note 3 – Regulatory Matters of Notes to DP&L's Financial Statements. In addition, DPLDPL's and DP&L's financial results are likely to be driven by manyother factors including, but not limited to:
regulatory outcomes;
Outcomethe passage of DP&L's pendingnew legislation, implementation of regulations or other changes in regulations;
timely recovery of transmission and distribution rate case;
DPL's ability to reduce its cost structure;
Operation and performance of generation facilities;
Recovery in the power market, particularly as it relates to an expansion in dark spreads;expenditures; and
PJM capacity prices.exiting generation assets currently owned by AES Ohio Generation.
Operational
During 2017, we began executing onAs part of our plansannounced plan to exit our generation by completingbusinesses, 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 Miami Fort and Zimmer EGUs and announcingNotes to DPL's Consolidated Financial Statements for additional information. In October 2018, AEP, the retirementoperator of co-owned Stuart Station coal-fired and diesel-fired generating units and the co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018. Further, on October 1, 2017, StuartConesville EGU, announced that Unit 1 was retired due to damage sustained when a high-pressure feedwater heater shell failed on January 10, 2017.
Additionally, on December 15, 2017 we entered into an agreement for the sale of the generation and related assets for our Peaker assets.4 would close by May 2020. For additional information on these events and DPL's coal fired facilities, see Note 415 – Property, Plant and Equipment and Note 17 – Assets and Liabilities Held-For-Sale and DispositionsDiscontinued Operations of Notes to DPL'sConsolidated Financial Statements.
Macroeconomic and Political
U.S.United States Tax Law Reform
On
In December 22, 2017, the United StatesU.S. federal government enacted the TCJA. The legislation significantly revised the U.S. corporate income tax system by, among other things, lowering the corporate income tax raterates and introducing new limitations on interest expense deductions.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&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 will beis 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 are expected to provide guidancehave released proposed regulations to clarify how the exception will apply to regulated utility holding companies. Depending on the guidance implementing the limitations, this could materially impact our effective tax rate.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.
SAB 118 - As further explained in Note 9 – 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 included certain reasonable estimates of the impact of U.S. tax law reform subject to potential adjustments in future periods.
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 98 – 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 settlementDistribution 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 2017 ESP caseDMR through October 2022, in January 2017 and filed an amended stipulation on March 13, 2017.the proposed amount of $199.0 million for each of the two additional years. The PUCO issued a final decision onrequest was made pursuant to the PUCO’s October 20, 2017 modifyingESP order, which approved the DMR and adoptinghad the amended stipulationoption 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 recommendation. The 2017 ESP establishesDPL and to position DP&L's&L to make capital expenditures to maintain and modernize its electric grid. To that end, 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. The signatory parties agreed to a six-year settlement that provides a framework for energy rates and defines other components.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’sDPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s&L's Financial Statements.
CAPITAL RESOURCES AND LIQUIDITY
Cash, and cash equivalents and restricted cash for DPL and DP&L was $24.5$111.7 million and $5.2$66.2 million, respectively, at December 31, 2017.2018. At that date, neither DPL nor DP&L had short-term investments. DPL and DP&L had aggregate principal amounts of debt outstanding of $1,724.01,488.4 million and $658.4593.8 million, respectively, at December 31, 2017.2018.
Approximately $4.7$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&L. . All material intercompany accounts and transactions have been eliminated in consolidation. The following table summarizes the cash flows of
Cash Flow Analysis - DPL:
| | | DPL | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Net cash provided by operating activities | | $ | 131.7 |
| | $ | 267.1 |
| | $ | 308.5 |
| | $ | 205.9 |
| | $ | 131.7 |
| | $ | 267.1 |
|
| Net cash used in investing activities | | (12.2 | ) | | (77.8 | ) | | (136.7 | ) | |
| Net cash provided by / (used in) investing activities | | | 129.9 |
| | (39.3 | ) | | (141.5 | ) |
| Net cash used in financing activities | | (149.6 | ) | | (167.1 | ) | | (156.4 | ) | | (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 | | (30.1 | ) | | 22.2 |
| | 15.4 |
| |
| Net increase / (decrease) in cash, cash equivalents and restricted cash | | | 86.8 |
| | (29.7 | ) | | (25.7 | ) |
| Balance at beginning of year | | 54.6 |
| | 32.4 |
| | 17.0 |
| | 24.9 |
| | 54.6 |
| | 80.3 |
|
| Cash and cash equivalents at end of year | | $ | 24.5 |
| | $ | 54.6 |
| | $ | 32.4 |
| |
| Cash, cash equivalents and restricted cash at end of year | | | $ | 111.7 |
| | $ | 24.9 |
| | $ | 54.6 |
|
DPL – Net cash from operating activities
| | | | | For the years ended December 31, | | $ change | | For the years ended December 31, | | $ change |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | | 2016 vs. 2015 | | 2018 | | 2017 | | 2016 | | 2018 vs. 2017 | | 2017 vs. 2016 |
| Net loss | | $ | (94.6 | ) | | $ | (485.2 | ) | | $ | (239.0 | ) | | $ | 390.6 |
| | $ | (246.2 | ) | |
| Net income / (loss) | | | $ | 70.1 |
| | $ | (94.6 | ) | | $ | (485.2 | ) | | $ | 164.7 |
| | $ | 390.6 |
|
| Depreciation and amortization | | 110.6 |
| | 138.0 |
| | 143.6 |
| | (27.4 | ) | | (5.6 | ) | | 55.7 |
| | 110.5 |
| | 137.9 |
| | (54.8 | ) | | (27.4 | ) |
| Impairment expenses | | 175.8 |
| | 859.0 |
| | 317.0 |
| | (683.2 | ) | | 542.0 |
| | 2.8 |
| | 175.8 |
| | 859.0 |
| | (173.0 | ) | | (683.2 | ) |
| Charge for early redemption of debt | | 3.3 |
| | 3.1 |
| | 2.1 |
| | 0.2 |
| | 1.0 |
| | 6.5 |
| | 3.3 |
| | 3.1 |
| | 3.2 |
| | 0.2 |
|
| Other adjustments to Net loss | | (21.7 | ) | | (359.7 | ) | | (10.9 | ) | | 338.0 |
| | (348.8 | ) | |
| Net loss, adjusted for non-cash items | | 173.4 |
| | 155.2 |
| | 212.8 |
| | 18.2 |
| | (57.6 | ) | |
| Other adjustments to Net income / (loss) | | | 2.0 |
| | (21.8 | ) | | (359.8 | ) | | 23.8 |
| | 338.0 |
|
| Net income / (loss), adjusted for non-cash items | | | 137.1 |
| | 173.2 |
| | 155.0 |
| | (36.1 | ) | | 18.2 |
|
| Net change in operating assets and liabilities | | (41.7 | ) | | 111.9 |
| | 95.7 |
| | (153.6 | ) | | 16.2 |
| | 68.8 |
| | (41.5 | ) | | 112.1 |
| | 110.3 |
| | (153.6 | ) |
| Net cash provided by operating activities | | $ | 131.7 |
| | $ | 267.1 |
| | $ | 308.5 |
| | $ | (135.4 | ) | | $ | (41.4 | ) | | $ | 205.9 |
| | $ | 131.7 |
| | $ | 267.1 |
| | $ | 74.2 |
| | $ | (135.4 | ) |
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 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 | | $ | (51.5 | ) |
| 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 | | (1.2 | ) |
| Net change in cash from changes in operating assets and liabilities | | $ | (153.6 | ) |
Fiscal year 2016 versus 2015:
The net change in operating assets and liabilities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was driven by the following:
| | | $ in millions | | $ Change | | $ change |
| Increase from inventory primarily due to lower coal purchases in 2016 | | $ | 41.0 |
| |
| Decrease from accounts receivable primarily due to timing of collections | | (19.2 | ) | |
| 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 | | (5.6 | ) | | (1.3 | ) |
| Net change in cash from changes in operating assets and liabilities | | $ | 16.2 |
| | $ | (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 forin investing activities was primarily relatedrelates to capital expenditures of $121.5 million, partially offset by a decrease in restricted cash due to collateral requirements, 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 forin investing activities was primarily relatedrelates to capital expenditures and an increase in restricted cash due to collateral requirements,of $148.5 million, partially offset by proceeds from the sale$6.3 million of DPLER.
During the year ended December 31, 2015, net cash used for investing activities was primarily related to capital expenditures.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 forin financing activities primarily relates to the retirement of $159.5 million of long-term debt.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 forin 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 a $442.8 millionthe issuance of new debt.long-term debt of $442.8 million.
During the year ended December 31, 2015, net cash used for financing activities primarily relates to the retirement of $474.5 million of long-term debt, partially offset by a $325.0 million issuance of new debt.
The following table summarizes the cash flows ofCash Flow Analysis - DP&L:
| | | DP&L | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Net cash provided by operating activities | | $ | 135.4 |
| | $ | 264.8 |
| | $ | 256.7 |
| | $ | 195.8 |
| | $ | 135.4 |
| | $ | 237.2 |
|
| Net cash used in investing activities | | (62.9 | ) | | (133.4 | ) | | (122.5 | ) | | (96.9 | ) | | (89.5 | ) | | (121.6 | ) |
| Net cash used in financing activities | | (68.9 | ) | | (135.2 | ) | | (134.2 | ) | | (38.3 | ) | | (68.9 | ) | | (135.2 | ) |
| Increase in cash and restricted cash of discontinued operations and held-for-sale businesses | | | — |
| | 27.0 |
| | 15.8 |
|
| | | | | | | | | | | | | |
| Net increase / (decrease) in cash | | 3.6 |
| | (3.8 | ) | | — |
| |
| Net increase / (decrease) in cash, cash equivalents and restricted cash | | | 60.6 |
| | 4.0 |
| | (3.8 | ) |
| Balance at beginning of year | | 1.6 |
| | 5.4 |
| | 5.4 |
| | 5.6 |
| | 1.6 |
| | 5.4 |
|
| Cash and cash equivalents at end of year | | $ | 5.2 |
| | $ | 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 | | For the years ended December 31, | | $ change |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2017 vs. 2016 | | 2016 vs. 2015 | | 2018 | | 2017 | | 2016 | | 2018 vs. 2017 | | 2017 vs. 2016 |
| Net income / (loss) | | $ | 17.0 |
| | $ | (772.7 | ) | | $ | 106.4 |
| | $ | 789.7 |
| | $ | (879.1 | ) | | $ | 86.7 |
| | $ | 17.0 |
| | $ | (772.7 | ) | | $ | 69.7 |
| | $ | 789.7 |
|
| Depreciation and amortization | | 88.3 |
| | 123.2 |
| | 141.1 |
| | (34.9 | ) | | (17.9 | ) | | 77.6 |
| | 88.3 |
| | 123.2 |
| | (10.7 | ) | | (34.9 | ) |
| Impairment expenses | | 66.3 |
| | 1,353.5 |
| | — |
| | (1,287.2 | ) | | 1,353.5 |
| | — |
| | 66.3 |
| | 1,353.5 |
| | (66.3 | ) | | (1,287.2 | ) |
| Other adjustments to Net income / (loss) | | 23.9 |
| | (481.2 | ) | | (8.3 | ) | | 505.1 |
| | (472.9 | ) | | 29.5 |
| | 23.9 |
| | (481.3 | ) | | 5.6 |
| | 505.2 |
|
| Net income / (loss), adjusted for non-cash items | | 195.5 |
| | 222.8 |
| | 239.2 |
| | (27.3 | ) | | (16.4 | ) | | 193.8 |
| | 195.5 |
| | 222.7 |
| | (1.7 | ) | | (27.2 | ) |
| Net change in operating assets and liabilities | | (60.1 | ) | | 42.0 |
| | 17.5 |
| | (102.1 | ) | | 24.5 |
| | 2.0 |
| | (60.1 | ) | | 14.5 |
| | 62.1 |
| | (74.6 | ) |
| Net cash provided by operating activities | | $ | 135.4 |
| | $ | 264.8 |
| | $ | 256.7 |
| | $ | (129.4 | ) | | $ | 8.1 |
| | $ | 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 | | $ | (64.0 | ) |
| 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 | | 23.0 |
|
| Decrease from inventory primarily due to lower coal purchases in 2016 | | (21.9 | ) |
Decrease from accrued taxes payable primarily due to 2017 tax sharing payments to DPL | | (7.0 | ) |
| Other | | (4.4 | ) |
| Net change in cash from changes in operating assets and liabilities | | $ | (102.1 | ) |
Fiscal year 2016 versus 2015:
The net change in operating assets and liabilities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was driven by the following:
| | | $ in millions | | $ Change | | $ change |
| Increase from inventory primarily due to lower coal purchases compared to prior year | | $ | 41.3 |
| |
| Decrease from accounts receivable primarily due to timing of collections | | (38.4 | ) | |
| Increase from accounts payable due to timing of payments | | 21.8 |
| |
| 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 | | (0.2 | ) | | (6.4 | ) |
| Net change in cash from changes in operating assets and liabilities | | $ | 24.5 |
| | $ | (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 forin investing activities was primarily relatedrelates to capital expenditures of $101.7 million, partially offset by a decrease in restricted cash due to collateral requirements and insurance proceeds.proceeds of $12.5 million.
During the year ended December 31, 2016, net cash used forin investing activities was primarily relatedrelates to capital expenditures and an increase in restricted cash due to collateral requirements,of $128.3 million, partially offset by insurance proceeds.proceeds of $6.1 million.
During the year ended December 31, 2015, net cash used for investing activities was primarily related to capital expenditures, partially offset by insurance proceeds.
DP&L – Net cash from financing activities
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 forin 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 forin financing activities primarily relates to the retirement of $445.3 million of long-term debt, $70.0 million in dividends paid on common stock to parent, related party repayments, net of related party borrowings, of $30.0 million, and redemption of $23.5 million of preferred stock, partially offset by the issuance of $442.8 million of new debt.
During the year ended December 31, 2015, net cash used for financing activities primarily relates to the retirement of $314.4 million of long-term debt, $50.0 million in dividends paid on common stock to parent, partially offset by the issuance of $200.0 million of new debt, and $35.0 million of related party borrowings.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 20182019 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&L. . See Note 3 – Regulatory Matters for more information.
At December 31, 2017,2018, DPL and DP&L have access to the following revolving credit facilities:
| | | $ in millions | | Type | | Maturity | | Commitment | | Amounts available as of December 31, 2017 | | Type | | Maturity | | Commitment | | Amounts available as of December 31, 2018 |
| DPL | | Revolving | | July 2020 | | $ | 205.0 |
| | $ | 188.9 |
| | Revolving | | July 2020 | | $ | 205.0 |
| | $ | 191.0 |
|
| | | | | | | | | |
| DP&L | | Revolving | | July 2020 | | 175.0 |
| | 163.6 |
| | Revolving | | July 2020 | | 175.0 |
| | 173.9 |
|
| | | | | | | | | |
| | | $ | 380.0 |
| | $ | 352.5 |
| | $ | 380.0 |
| | $ | 364.9 |
|
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, 2017,2018, DP&L had $10.0 millionnothing drawn under this facility and had two lettersone letter of credit in the aggregate amount of $1.4$1.1 million outstanding, with the remaining $163.6$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 September 30, 2017,December 31, 2018, there were five letters of credit in the aggregate amount of $12.9$14.0 million outstanding under this facility, and $50.0 millionnothing borrowed on the facility, with the remaining $142.1$191.0 million available to DPLDPL. . Fees associated with this facility were not material during the years ended December 31, 2018, 2017 2016 or 2015.
On December 15, 2017, shortly after DPL and AES Ohio Generation entered into an Asset Purchase Agreement agreeing to sell Peaker assets to Kimura Power, DPL and its lenders amended DPL's revolving credit loan and term loan credit agreement. This agreement was amended to, among other things, (a) explicitly carve out the sale of DPL's Peaker assets and coal generation facilities from its "limitation on asset disposition" covenant, (b) modify the definition of Consolidated EBITDA (which is used for measuring the Consolidated Debt to EBITDA ratio and the Interest Coverage Ratio in the agreement), to also exclude, out-of-pocket third party costs and expenses incurred directly in connection with the implementation, negotiation, documentation and closing of the Generation Separation and up to $25.0 million of non-recurring cash expenses related to the closure, or sale, of generation stations, (c) modify the definition of "maturity date" used in the agreement to mean July 31, 2020; provided, however, if DPL fails to retire, redeem, or refinance at least $100.0 million in aggregate of principal amount of its senior unsecured bonds due October 1, 2019, then the maturity date shall be July, 1 2019, and (d) modify the maximum Consolidated Debt to EBITDA ratio permitted not to exceed 7.25 to 1.00 September 20, 2015 through December 31, 2018, 7.00 to 1.00 January 1, 2019 through June 30, 2019, 6.75 to 1.00 July 1, 2019 through December 31, 2019, and 6.50 to 1.00 January 1, 2020 and beyond. As part of this agreement DPL has also agreed to repay the remaining balance on its secured term loan within 10 days after receiving proceeds from the sale of the Peaker assets. This agreement was effective December 15, 2017, however certain provisions, including the modification of the Consolidated Debt to EBITDA covenant and the carving out of the sale of Peaker assets from its "limitation on asset disposition" covenant, are conditioned on the repayment in full of the term loan.2016.
Capital Requirements
Construction Additions
| | | | | Actual | | Projected | | Actual | | Projected |
| $ in millions | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| DPL | | $ | 132 |
| | $ | 140 |
| | $ | 108 |
| | $ | 90 |
| | $ | 120 |
| | $ | 148 |
| | $ | 140 |
| | $ | 108 |
| | $ | 84 |
| | $ | 143 |
| | $ | 223 |
| | $ | 262 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| DP&L | | $ | 91 |
| | $ | 88 |
| | $ | 83 |
| | $ | 84 |
| | $ | 115 |
| | $ | 138 |
| | $ | 88 |
| | $ | 83 |
| | $ | 82 |
| | $ | 140 |
| | $ | 221 |
| | $ | 260 |
|
Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards,laws, rules and regulations, among other factors.
DPL is projecting to spend an estimated $358.0$628.0 million in capital projects for the period 20182019 through 2020.2021, 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 $33.0$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
TheFor information regarding our long-term debt covenants, see Note 7 – Long-term debt of Notes to DPLDPL's revolving credit facilityConsolidated Financial Statements and term loan agreement have a Total DebtNote 7 – Long-term debt of Notes to EBITDA ratio that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down to not exceed 6.25 to 1.00 for any fiscal quarter ending March 31, 2019 through December 31, 2019; and it then steps down not to exceed 5.75 to 1.00 for any fiscal quarter ending March 31, 2020 through July 31, 2020. As of December 31, 2017, this financial covenant was met with a ratio of 6.34 to 1.00.
The DPL revolving credit facility and term loan agreement also have an EBITDA to Interest Expense ratio that is calculated at the end of each fiscal quarter by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, per the agreements, is to be not less than 2.10 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps up to be not less than 2.25 to 1.00 for any fiscal quarter ending March 31, 2019 through July 31, 2020. As of December 31, 2017, this financial covenant was met with a ratio of 2.50 to 1.00.
DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, which occurred October 1, 2017, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time. Except that after separation required compliance with this financial covenant shall be suspended (a) any time after separation during which DP&L maintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility or (b) for the time period January 1, 2017 to December 31, 2017 (as modified by the amendment described below) if DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt.
On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L was able to ensure compliance with theTotal Debt to Total Capitalization ratio through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement (before any amendment), the required Total Debt to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total Debt to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00. After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L (or from October 1, 2017 through September 30, 2018). Generation Separation occurred on October 1, 2017.
The second financial covenant measures DP&L’s EBITDA to Interest Expense ratio. Both prior to and after completion of the separation of DP&L's generation assets from its transmission and distribution assets, DP&L's EBITDA to Interest Expense ratio cannot be less than 2.50 to 1.00. The ratio is calculated at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the interest charges for the same period. As of December 31, 2017, DP&L met this financial covenant with an EBITDA to Interest Expense ratio of 7.17 to 1.00.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-BBB(a) / BB+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) | | PositiveStable | | October 2017March 2018 |
| |
Moody's Investors Service, Inc.(a) | Ba3Rating relates to (b)DPL’s senior secured debt.
|
| |
| (b) | Baa2Rating relates to (c)DPL's senior unsecured debt.
|
| Positive | | October 2017 |
Standard & Poor's Financial Services LLC(c) | BBRating relates to (b)DP&L’s senior secured debt.
| | BBB (c)
| | Positive | | December 2017 |
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.
|
| | | | | | | |
| | DPL | | DP&L | | Outlook | | Effective or Affirmed |
| Fitch Ratings | BBBBB- | | BBB-BBB | | Stable | | October 2018 |
| Moody's Investors Service, Inc. | Ba1 | | Baa2 | | Positive | | October 2017 |
Moody's Investors Service, Inc. | Ba3 | | Baa3 | | Positive | | October 20172018 |
| Standard & Poor's Financial Services LLC | BBBBB- | | BBBBB- | | PositiveStable | | December 2017March 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.
|
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 such as DPL, may experience higher costs to issue new securities.DP&L is still considered investment grade by one of the three rating agencies above.
Off-Balance Sheet Arrangements
DPL – Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiary, AES Ohio Generation, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish this subsidiary's intended commercial
purposes. During the year ended December 31, 2017,2018, 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, 2017,2018, DPL had $38.1$23.6 million of guarantees on behalf of AES Ohio Generation to third parties for future financial or performance assurance under such agreements on behalf of AES Ohio Generation.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 and $2.3 million at December 31, 2016.2017.
DP&L owns a 4.9% equity ownership interest in an electric generation companyOVEC which is recorded using the cost method of accounting under GAAP. At December 31, 2017,2018, DP&L could be responsible for the repayment of 4.9%, or $70.6$68.1 million, of a $1,440.8$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, 2017,2018, 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, 2017,2018, these include:
| | | | | Payments due in: | | Payments due in: |
| $ in millions | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years |
| DPL: | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | $ | 1,724.0 |
| | $ | 4.7 |
| | $ | 479.1 |
| | $ | 1,207.5 |
| | $ | 32.7 |
| | $ | 1,488.4 |
| | $ | 103.6 |
| | $ | 929.4 |
| | $ | 423.0 |
| | $ | 32.4 |
|
| Interest payments | | 384.7 |
| | 98.9 |
| | 176.4 |
| | 81.2 |
| | 28.2 |
| | 274.4 |
| | 86.6 |
| | 145.3 |
| | 15.9 |
| | 26.6 |
|
| Pension and postretirement payments | | 283.2 |
| | 30.0 |
| | 59.2 |
| | 57.6 |
| | 136.4 |
| | 264.6 |
| | 27.8 |
| | 54.7 |
| | 53.6 |
| | 128.5 |
|
| Electricity purchase commitments | | 370.9 |
| | 178.5 |
| | 171.2 |
| | 21.2 |
| | — |
| | 209.4 |
| | 139.5 |
| | 69.9 |
| | — |
| | — |
|
Coal and limestone contracts (a) | | 54.9 |
| | 54.9 |
| | — |
| | — |
| | — |
| |
| Purchase orders and other contractual obligations | | 73.0 |
| | 18.9 |
| | 27.1 |
| | 27.0 |
| | — |
| | 40.2 |
| | 11.4 |
| | 14.8 |
| | 14.0 |
| | — |
|
| Total contractual obligations | | $ | 2,890.7 |
| | $ | 385.9 |
| | $ | 913.0 |
| | $ | 1,394.5 |
| | $ | 197.3 |
| | $ | 2,277.0 |
| | $ | 368.9 |
| | $ | 1,214.1 |
| | $ | 506.5 |
| | $ | 187.5 |
|
| |
(a) | Total at DP&L operated units.
|
| | | | | Payments due in: | | Payments due in: |
| $ in millions | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years |
| DP&L: | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | $ | 658.4 |
| | $ | 4.6 |
| | $ | 209.2 |
| | $ | 427.5 |
| | $ | 17.1 |
| | $ | 593.8 |
| | $ | 4.6 |
| | $ | 149.4 |
| | $ | 423.0 |
| | $ | 16.8 |
|
| Interest payments | | 123.2 |
| | 24.8 |
| | 47.3 |
| | 33.9 |
| | 17.2 |
| | 94.5 |
| | 23.7 |
| | 41.0 |
| | 13.4 |
| | 16.4 |
|
| Pension and postretirement payments | | 283.2 |
| | 30.0 |
| | 59.2 |
| | 57.6 |
| | 136.4 |
| | 264.6 |
| | 27.8 |
| | 54.7 |
| | 53.6 |
| | 128.5 |
|
| Electricity purchase commitments | | 370.9 |
| | 178.5 |
| | 171.2 |
| | 21.2 |
| | — |
| | 209.4 |
| | 139.5 |
| | 69.9 |
| | — |
| | — |
|
| Purchase orders and other contractual obligations | | 73.0 |
| | 18.9 |
| | 27.1 |
| | 27.0 |
| | — |
| | 39.8 |
| | 11.3 |
| | 14.7 |
| | 13.8 |
| | — |
|
| Total contractual obligations | | $ | 1,508.7 |
| | $ | 256.8 |
| | $ | 514.0 |
| | $ | 567.2 |
| | $ | 170.7 |
| | $ | 1,202.1 |
| | $ | 206.9 |
| | $ | 329.7 |
| | $ | 503.8 |
| | $ | 161.7 |
|
Long-term debt:
DPL’s Long-term debt at December 31, 20172018 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-PattersonWright-
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, 20172018 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 87 – DebtLong-term debt of the Notes to DPL’sDPL's Consolidated Financial Statements and Note 7 – DebtLong-term debt of the Notes to DP&L’s&L's Financial Statements.
Interest payments:
Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailingrates in effect at December 31, 2017.2018.
Pension and postretirement payments:
At December 31, 2017,2018, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 109 – Benefit Plans of Notes to DPL’sDPL's Consolidated Financial Statements and Note 9 – Benefit Plans of Notes to DP&L’s&L's Financial Statements. These estimated future benefit payments are projected through 2027.2028. 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.
Coal contracts:
DPL, through its subsidiary AES Ohio Generation, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2017, a majority of our future committed coal obligations are with one supplier. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year. As a result of our planned shutdown of our Stuart and Killen generating stations, our commitments for coal and limestone do not extend past 2018.
Purchase orders and other contractual obligations:
At December 31, 2017,2018, 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 1312 – 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, 2017,2018, 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 Recognition (including Unbilled Revenue)
We consider revenue realized, or realizable,Revenue is primarily earned from retail and earned when persuasive evidencewholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of an arrangement exists, the productscontrol of promised goods or services have been providedto 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 customer, the sales price is fixed or determinable, and collection is reasonably assured. The determination of energy sales to customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. We recognize revenues using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, projected line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Given our estimation method and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.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’sDPL's Consolidated Financial Statements and Note 3 – Regulatory Matters of Notes to DP&L’s&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&L's Financial Statements for more information.
Impairments
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. See Note 15 – Fixed-asset Impairments of Notes to DPL’s Consolidated Financial Statements discussing the impairment of long-lived assets in 2017 and 2016.
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 109 – Benefit Plans of Notes to DPL’sDPL's Consolidated Financial Statements and Note 9 – Benefit Plans of Notes to DP&L’s&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’sDPL's Consolidated Financial Statements and Note 1 – Overview and Summary of Significant Accounting Policies of Notes to DP&L’s&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"Environmental Matters", Item 1 – Business "Competition"Competition and Regulation" and Item 3 – Legal Proceedings. Such discussions are incorporated by reference in this Management's Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.
|
|
| Item 7A – Quantitative and Qualitative Disclosures about Market Risk |
We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity coal, environmental emission allowances, and changes in capacity prices and fluctuations in interest rates. We use various market risk-sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing.interest rates. Our CommodityU.S. Risk Management Committee (CRMC)(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 DPL operated generation units.operations. The CRMCU.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.
Commodity pricing risk
Commodity pricing risk exposure includes the impacts of weather, market demand, increased competition and other economic conditions. To manage the volatility relating to these exposures at our DPL-operated generation units, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value monthly through the Statement of Operations.
The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile thandisclosures presented in the past, and while we have substantially all of the total expected coal volume needed to meet our sales requirements for 2018 under contract, power sales obligations may change. Fuel coststhis section are affected by changes in volume and price and are driven bybased upon a number of variables including weather,assumptions; actual effects may differ. The safe harbor provided in Section 27A of the wholesale market priceSecurities Act of power, certain provisions in coal contracts related to government-imposed costs, counterparty performance1933 and credit, scheduled outages and electric generation station mix.Section 21E of the Securities Exchange Act of
In addition,1934 shall apply to the Dodd-Frank Wall Street Reformdisclosures contained in this section. For further information regarding market risk, see Item 1A.-Risk Factors. Our businesses may incur substantial costs and Consumer Protection Act (the "Dodd-Frank Act"), signed into law in July 2010, contains significant requirements relatingliabilities and be exposed to derivatives, including, among others,price volatility as a requirement that certain transactions be cleared on exchanges that would necessitateresult of risks associated with 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 iselectricity markets, which could have a major swap participant or has elected to reportmaterial adverse effect on our behalf. Even thoughfinancial performance; and we qualify for an exception from these requirements,may not be adequately hedged against our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductionsexposure to changes in unsecured credit limits or be unable to enter into certain transactions with us.interest rates.
For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.
Commodity derivatives
To minimize the risk of fluctuations in the market price of commodities, such as coal,Purchased power and natural gas, we may enter into commodity forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between us and the counterparty at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months. At December 31, 2017, there are no coal derivatives.
A 10% increase or decrease in the market price of our FTRs and natural gas futures at December 31, 2017 would not have a significant effect on Net income.
A 10% increase or decrease in the market price of our forward power contracts at December 31, 2017 would not have a significant effect on Net income.
Wholesale revenues
DPL sells its generation into the wholesale market when we can identify opportunities with positive margins.
Approximately 43% of DPL’s electric revenues during the year ended December 31, 2017 were from sales of excess energy and capacity in the wholesale market.
For DPL, a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power, including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale, would result in an approximate $20.9 million change to net income.
Fuel and purchased power costs
We have a significant portion of projected 2018 fuel needs under contract. Most of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2 allowances for 2018; however, the exact consumption of SO2 allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOX allowances for 2018 depending on NOX emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and electric generation station mix.
DP&L conducts competitive bid auctions to purchase power for SSO service, as all of DP&L'sSSO is 100% sourced through the competitive bid. AES Ohio Generation purchases power to source retail load in other service territories and to meet contracted wholesale requirements when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.bid auction.
The table below providesAs a result of DPL's exit from the effect on annual Net income (netmajority of estimated income tax at 35%) as of December 31, 2017, of a hypothetical increase or decrease of 10%its coal-fired generation, changes in the prices of fuel and purchased power:
|
| | | | | | | | |
| $ in millions | | DPL | | DP&L |
| Effect of 10% change in fuel and purchased power | | $ | 22.7 |
| | $ | 5.8 |
|
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.DPL’s variable-rate debt consists of a $70.0 million secured term loan with a syndicated bank group. DP&L’s variable-rate debt is comprised of $200 million of bank held tax-exempt First Mortgage Bonds and $440.6 million Term Loan B debt secured by First Mortgage Bonds. Each variable-rate bond bears interest based on an underlying interest rate index, typically LIBOR. On November 21, 2016, the DP&L $200.0 million variable-rate First Mortgage Bonds were hedged with 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 87 – DebtLong-term debt of Notes to DPL’sDPL's Consolidated Financial Statements and Note 7 – DebtLong-term debt of Notes to DP&L’s&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 $1,724.0$1,488.4 million at December 31, 2017,2018, 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, 20172018 was $1,819.3$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:
| | | DPL | | Years ending December 31, | | | | Principal amount at December 31, | | Fair value at December 31, | | Years ending December 31, | | | | Principal amount at December 31, | | Fair value at December 31, |
| $ in millions | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | 2017 | | 2017 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | 2018 | | 2018 |
Long-term debt (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Variable-rate debt | | $ | 4.5 |
| | $ | 24.4 |
| | $ | 254.4 |
| | $ | 4.5 |
| | $ | 422.8 |
| | $ | — |
| | $ | 710.6 |
| | $ | 710.6 |
| | $ | 4.5 |
| | $ | 144.5 |
| | $ | 4.5 |
| | $ | 422.6 |
| | $ | — |
| | $ | — |
| | $ | 576.1 |
| | $ | 576.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average interest rate | | 4.6 | % | | 4.2 | % | | 2.4 | % | | 4.6 | % | | 4.6 | % | | | | | | | | 4.4 | % | | 3.0 | % | | 4.4 | % | | 4.4 | % | | — | % | | — | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed-rate debt | | $ | 0.2 |
| | $ | 200.1 |
| | $ | 0.2 |
| | $ | 780.1 |
| | $ | 0.1 |
| | $ | 32.7 |
| | 1,013.4 |
| | 1,108.7 |
| | $ | 99.1 |
| | $ | 0.2 |
| | $ | 780.2 |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | 32.4 |
| | 912.3 |
| | 943.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average interest rate | | 4.2 | % | | 6.7 | % | | 4.2 | % | | 7.2 | % | | 4.2 | % | | 6.1 | % | | | | | | 6.7 | % | | 4.2 | % | | 7.2 | % | | 4.2 | % | | 4.2 | % | | 6.1 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | | | | | | | | | | | | $ | 1,724.0 |
| | $ | 1,819.3 |
| | | | | | | | | | | | | | $ | 1,488.4 |
| | $ | 1,519.6 |
|
| |
(a) | Amounts exclude immaterial capital lease obligations |
The principal amount of DP&L’s long-term debt was $658.4$593.8 million at December 31, 2017,2018, consisting of its First Mortgage Bonds, tax-exempt First Mortgage Bonds and the WPAFB note. The fair value of this debt at December 31, 20172018 was $658.4$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 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | 2017 | | 2017 |
Long-term debt (a) | | | | | | | | | | | | | | | | |
| Variable-rate debt | | $ | 4.5 |
| | $ | 4.4 |
| | $ | 204.4 |
| | $ | 4.4 |
| | $ | 422.7 |
| | $ | — |
| | $ | 640.4 |
| | $ | 640.6 |
|
| | | | | | | | | | | | | | | | | |
| Average interest rate | | 4.6 | % | | 4.6 | % | | 2.0 | % | | 4.6 | % | | 4.6 | % | | — | % | | | | |
| | | | | | | | | | | | | | | | | |
| Fixed-rate debt | | $ | 0.1 |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | 17.1 |
| | 18.0 |
| | 17.8 |
|
| | | | | | | | | | | | | | | | | |
| Average interest rate | | 4.2 | % | | 4.2 | % | | 4.2 | % | | 4.2 | % | | 4.2 | % | | 4.2 | % | | | | |
| | | | | | | | | | | | | | | | | |
| Total | | | | | | | | | | | | | | $ | 658.4 |
| | $ | 658.4 |
|
| |
(a) | Amounts exclude immaterial capital lease obligations |
Long-term debt interest rate risk sensitivity analysis
Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at December 31, 2017 and 2016 for which an immediate adverse market movement causes a potential material effect on our financial condition, results of operations, or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. At December 31, 2017 and 2016, we did not hold any market risk sensitive instruments which were entered into for trading purposes.
Principal value and fair value of debt with one percent interest rate risk
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| DPL | | | | | | | | | | | | |
| $ in millions | | Principal amount at December 31, 2017 | | Fair value at December 31, 2017 | | One Percent
Interest Rate
Risk | | Principal amount at December 31, 2016 | | Fair value at December 31, 2016 | | One Percent
Interest Rate
Risk |
Long-term debt (a) | | | | | | | | | | | | |
Variable-rate debt(c) | | $ | 710.6 |
| | $ | 710.6 |
| | $ | 7.1 |
| | $ | 570.0 |
| | $ | 570.0 |
| | $ | 5.7 |
|
| | | | | | | | | | | | | |
Fixed-rate debt (b) | | 1,013.4 |
| | 1,108.7 |
| | 10.1 |
| | 1,313.6 |
| | 1,337.7 |
| | 13.1 |
|
| | | | | | | | | | | | | |
| Total | | $ | 1,724.0 |
| | $ | 1,819.3 |
| | $ | 17.2 |
| | $ | 1,883.6 |
| | $ | 1,907.7 |
| | $ | 18.8 |
|
| |
(a) | Amounts exclude immaterial capital lease obligations |
| |
(b) | In 2016, fixed-rate debt includes $200.0 million DP&L Tax-exempt First Mortgage Bonds that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DPL's Consolidated Financial Statements.
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| DP&L | | | | | | | | | | | | |
| $ in millions | | Principal amount at December 31, 2017 | | Fair value at December 31, 2017 | | One Percent
Interest Rate
Risk | | Principal amount at December 31, 2016 | | Fair value at December 31, 2016 | | One Percent
Interest Rate
Risk |
Long-term debt (a) | | | | | | | | | | | | |
| Variable-rate debt | | $ | 640.6 |
| | $ | 640.6 |
| | $ | 6.4 |
| | $ | 445.0 |
| | $ | 445.0 |
| | $ | 4.5 |
|
| | | | | | | | | | | | | |
Fixed-rate debt (b) | | 17.8 |
| | 17.8 |
| | 0.2 |
| | 318.0 |
| | 318.5 |
| | 3.2 |
|
| | | | | | | | | | | | | |
| Total | | $ | 658.4 |
| | $ | 658.4 |
| | $ | 6.6 |
| | $ | 763.0 |
| | $ | 763.5 |
| | $ | 7.7 |
|
| |
(a) | Amounts exclude immaterial capital lease obligations |
| |
(b) | In 2016, fixed-rate debt includes $200.0 million DP&L Tax-exempt First Mortgage Bonds that have been hedged, per discussion above. See Note 6 – Derivative Instruments and Hedging Activities of Notes to DP&L's Consolidated Financial Statements.
|
DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $1,108.7 million of fixed-rate debt and not on DPL’s financial condition or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DPL’s $710.6 million variable-rate long-term debt outstanding at December 31, 2017.
DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $17.8 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $640.6 million variable-rate long-term debt outstanding at December 31, 2017. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2017,2018, approximately 35%33% of the defined benefit pension plan assets were comprised of investments in equity securities and 65%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 $124.5$105.2 million at December 31, 2017.2018. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12.5$10.5 million reduction in fair value at December 31, 20172018 and approximately a $1.8$1.6 million increase to the 20182019 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&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.
FINANCIAL STATEMENTS
DPL INC.
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, 20172018 and 2016,2017, the related consolidated statements of operations, comprehensive loss,income / (loss), cash flows and shareholder’s equity for each of the three years in the period ended December 31, 2017,2018, and the related notes and schedulesschedule (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, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172018 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 December 31, 2017 and 2016 audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America and our December 31, 2015 audit in accordance with the standards of the PCAOB.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.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2011.
Indianapolis, Indiana
February 26, 20182019
| | DPL INC. | | CONSOLIDATED STATEMENTS OF OPERATIONS | |
| Consolidated Statements of Operations | | Consolidated Statements of Operations |
| | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Revenues | | $ | 1,236.9 |
| | $ | 1,427.3 |
| | $ | 1,612.8 |
| | $ | 775.9 |
| | $ | 743.9 |
| | $ | 834.2 |
|
| | | | | | | | | | | | | |
| Cost of revenues: | | | | | | | | | | | | |
| Net fuel cost | | 210.3 |
| | 268.8 |
| | 259.8 |
| | 17.5 |
| | 9.0 |
| | 17.4 |
|
| Net purchased power cost | | 339.2 |
| | 417.4 |
| | 562.6 |
| | 305.0 |
| | 291.0 |
| | 319.1 |
|
| Total cost of revenues | | 549.5 |
| | 686.2 |
| | 822.4 |
| | 322.5 |
| | 300.0 |
| | 336.5 |
|
| | | | | | | | | | | | | |
| Gross margin | | 687.4 |
| | 741.1 |
| | 790.4 |
| | 453.4 |
| | 443.9 |
| | 497.7 |
|
| | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | |
| Operation and maintenance | | 327.6 |
| | 348.1 |
| | 361.3 |
| | 156.8 |
| | 186.1 |
| | 213.5 |
|
| Depreciation and amortization | | 106.9 |
| | 132.3 |
| | 134.6 |
| | 73.1 |
| | 76.1 |
| | 73.6 |
|
| General taxes | | 89.7 |
| | 85.7 |
| | 87.0 |
| | 73.5 |
| | 77.1 |
| | 68.4 |
|
| Goodwill impairment (Note 7) | | — |
| | — |
| | 317.0 |
| |
| Fixed-asset impairment (Note 15) | | 175.8 |
| | 859.0 |
| | — |
| |
| Other, net (Note 2) | | (6.6 | ) | | (0.1 | ) | | 0.4 |
| |
| 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 | | 693.4 |
| | 1,425.0 |
| | 900.3 |
| | 317.9 |
| | 338.7 |
| | 378.7 |
|
| | | | | | | | | | | | | |
| Operating loss | | (6.0 | ) | | (683.9 | ) | | (109.9 | ) | |
| Operating income | | | 135.5 |
| | 105.2 |
| | 119.0 |
|
| | | | | | | | | | | | | |
| Other income / (expense), net | | | | | | | | | | | | |
| Investment income | | 0.3 |
| | 0.4 |
| | 0.2 |
| |
| Interest expense | | (110.1 | ) | | (107.7 | ) | | (119.8 | ) | | (98.0 | ) | | (110.0 | ) | | (107.4 | ) |
| Charge for early redemption of debt | | (3.3 | ) | | (3.1 | ) | | (2.1 | ) | | (6.5 | ) | | (3.3 | ) | | (3.1 | ) |
| Other income / (expense) | | (0.8 | ) | | 1.0 |
| | 0.2 |
| |
| Other income | | | 0.9 |
| | 1.6 |
| | 3.9 |
|
| Other expense, net | | (113.9 | ) | | (109.4 | ) | | (121.5 | ) | | (103.6 | ) | | (111.7 | ) | | (106.6 | ) |
| | | | | | | | | | | | | |
| Loss from continuing operations before income tax | | (119.9 | ) | | (793.3 | ) | | (231.4 | ) | |
| Income / (loss) from continuing operations before income tax | | | 31.9 |
| | (6.5 | ) | | 12.4 |
|
| | | | | | | | | | | | | |
| Income tax expense / (benefit) from continuing operations | | (25.3 | ) | | (278.8 | ) | | 20.0 |
| | 0.7 |
| | (5.0 | ) | | (2.4 | ) |
| | | | | | | | | | | | | |
| Net loss from continuing operations | | (94.6 | ) | | (514.5 | ) | | (251.4 | ) | |
| Net income / (loss) from continuing operations | | | 31.2 |
| | (1.5 | ) | | 14.8 |
|
| | | | | | | | |
|
| |
|
| |
|
|
| Discontinued operations (Note 16) | | | | | | | |
| Income / (loss) from discontinued operations | | — |
| | (0.7 | ) | | 11.4 |
| |
| Gain from disposal of discontinued operations | | — |
| | 49.2 |
| | — |
| |
| Discontinued operations (Note 15) | | | | | | | |
| Income / (loss) from discontinued operations before income tax | | | 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 | | — |
| | 19.2 |
| | (1.0 | ) | | 30.0 |
| | (20.3 | ) | | (257.2 | ) |
| Net income from discontinued operations | | — |
| | 29.3 |
| | 12.4 |
| |
| Net income / (loss) from discontinued operations | | | 38.9 |
| | (93.1 | ) | | (500.0 | ) |
| | | | | | | | |
|
| |
|
| |
|
|
| Net loss | | $ | (94.6 | ) | | $ | (485.2 | ) | | $ | (239.0 | ) | |
| Net income / (loss) | | | $ | 70.1 |
| | $ | (94.6 | ) | | $ | (485.2 | ) |
See Notes to Consolidated Financial Statements.
|
| | | | | | | | | | | | |
| DPL INC. |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS |
| | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 |
| Net loss | | $ | (94.6 | ) | | $ | (485.2 | ) | | $ | (239.0 | ) |
| Available-for-sale securities activity: | | | | | | |
| Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of ($0.2), ($0.1) and $0.1 for each respective period | | 0.5 |
| | 0.2 |
| | (0.1 | ) |
| Reclassification to earnings, net of income tax benefit / (expense) of $0.0, $0.0 and $0.0 for each respective period | | (0.1 | ) | | — |
| | — |
|
| Net change in fair value of available-for-sale securities | | 0.4 |
| | 0.2 |
| | (0.1 | ) |
| Derivative activity: | | | | | | |
| Change in derivative fair value, net of income tax benefit / (expense) of ($5.3), ($8.8) and ($10.3) for each respective period | | 9.6 |
| | 16.1 |
| | 18.2 |
|
| Reclassification to earnings, net of income tax benefit / (expense) of $4.4, $16.7 and $5.4 for each respective period | | (8.0 | ) | | (29.7 | ) | | (10.0 | ) |
| Net change in fair value of derivatives | | 1.6 |
| | (13.6 | ) | | 8.2 |
|
| Pension and postretirement activity: | | | | | | |
| Prior service cost for the period, net of income tax benefit / (expense) of $0.4, $0.0 and $0.0 for each respective period | | (0.7 | ) | | — |
| | — |
|
| Net gain / (loss) for the period, net of income tax benefit / (expense) of $1.1, $2.4 and ($1.2) for each respective period | | (1.8 | ) | | (4.7 | ) | | 1.6 |
|
| Reclassification to earnings, net of income tax benefit / (expense) of ($0.5), ($0.6) and ($0.2) for each respective period | | 1.0 |
| | 1.0 |
| | 0.2 |
|
| Net change in unfunded pension and postretirement obligations | | (1.5 | ) | | (3.7 | ) | | 1.8 |
|
| | | | | | | |
| Other comprehensive income / (loss) | | 0.5 |
| | (17.1 | ) | | 9.9 |
|
| | | | | | | |
| Net comprehensive loss | | $ | (94.1 | ) | | $ | (502.3 | ) | | $ | (229.1 | ) |
|
| | | | | | | | | | | | |
| DPL INC. |
| 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 | | 0.1 |
| | (1.5 | ) | | (3.7 | ) |
| | | | | | | |
| Other comprehensive income / (loss) | | 2.4 |
| | 0.5 |
| | (17.1 | ) |
| | | | | | | |
| Net comprehensive income / (loss) | | $ | 72.5 |
| | $ | (94.1 | ) | | $ | (502.3 | ) |
See Notes to Consolidated Financial Statements.
| | DPL INC. | | CONSOLIDATED BALANCE SHEETS | |
| Consolidated Balance Sheets | | Consolidated Balance Sheets |
| $ in millions | | December 31, 2017 | | December 31, 2016 | | December 31, 2018 | | December 31, 2017 |
| ASSETS | | | | | |
| |
|
| Current assets: | |
| |
| |
| |
|
| Cash and cash equivalents | | $ | 24.5 |
| | $ | 54.6 |
| | $ | 90.5 |
| | $ | 24.5 |
|
| Restricted cash | | 1.9 |
| | 29.0 |
| | 21.2 |
| | 0.4 |
|
| Accounts receivable, net (Note 2) | | 98.7 |
| | 135.1 |
| | 90.5 |
| | 64.6 |
|
| Inventories (Note 2) | | 24.5 |
| | 77.2 |
| | 10.7 |
| | 12.7 |
|
| Taxes applicable to subsequent years | | 73.8 |
| | 81.0 |
| | 72.6 |
| | 71.3 |
|
| Regulatory assets, current (Note 3) | | 23.9 |
| | 0.1 |
| | 41.1 |
| | 23.9 |
|
| Other prepayments and current assets | | 27.9 |
| | 31.8 |
| | 12.9 |
| | 12.6 |
|
| Assets held-for-sale - current (Note 17) | | 250.3 |
| | — |
| |
| Current assets of discontinued operations and held-for-sale businesses (Note 15) | | | 8.7 |
| | 315.6 |
|
| Total current assets | | 525.5 |
| | 408.8 |
| | 348.2 |
| | 525.6 |
|
| | | | | | | | | |
| Property, plant and equipment: | |
| |
| |
| |
|
| Property, plant and equipment | | 1,554.7 |
| | 1,985.6 |
| | 1,615.6 |
| | 1,544.1 |
|
| Less: Accumulated depreciation and amortization | | (278.6 | ) | | (334.8 | ) | | (310.8 | ) | | (269.1 | ) |
| | | 1,276.1 |
| | 1,650.8 |
| | 1,304.8 |
| | 1,275.0 |
|
| Construction work in process | | 48.8 |
| | 116.4 |
| | 32.2 |
| | 46.5 |
|
| Total net property, plant and equipment | | 1,324.9 |
| | 1,767.2 |
| | 1,337.0 |
| | 1,321.5 |
|
| Other non-current assets: | |
| |
| |
| |
|
| Regulatory assets, non-current (Note 3) | | 163.2 |
| | 203.9 |
| | 152.6 |
| | 163.2 |
|
| Intangible assets, net of amortization | | 21.1 |
| | 22.7 |
| | 18.4 |
| | 18.8 |
|
| Other deferred assets | | 14.5 |
| | 16.6 |
| | 21.6 |
| | 13.8 |
|
| Non-current assets of discontinued operations and held-for-sale businesses (Note 15) | | | 5.3 |
| | 6.3 |
|
| Total other non-current assets | | 198.8 |
| | 243.2 |
| | 197.9 |
| | 202.1 |
|
| | | | | | | | | |
| Total Assets | | $ | 2,049.2 |
| | $ | 2,419.2 |
| | $ | 1,883.1 |
| | $ | 2,049.2 |
|
| | | | | | | | | |
| LIABILITIES AND SHAREHOLDER'S EQUITY | |
| |
| |
| |
|
| Current liabilities: | |
| |
| |
| |
|
| Current portion - long-term debt (Note 8) | | $ | 4.7 |
| | $ | 29.7 |
| |
| Current portion - long-term debt (Note 7) | | | $ | 103.6 |
| | $ | 4.6 |
|
| Short-term debt | | 10.0 |
| | — |
| | — |
| | 10.0 |
|
| Accounts payable | | 70.1 |
| | 113.9 |
| | 58.1 |
| | 48.9 |
|
| Accrued taxes | | 80.0 |
| | 185.1 |
| | 76.7 |
| | 77.3 |
|
| Accrued interest | | 16.4 |
| | 17.7 |
| | 14.3 |
| | 16.4 |
|
| Customer security deposits | | 21.8 |
| | 15.2 |
| | 21.3 |
| | 21.8 |
|
| Regulatory liabilities, current (Note 3) | | 14.8 |
| | 33.7 |
| | 34.9 |
| | 14.8 |
|
| Insurance and claims costs | | 3.0 |
| | 5.4 |
| |
| Other current liabilities | | 42.8 |
| | 50.2 |
| | 22.0 |
| | 16.2 |
|
| Liabilities held-for-sale - current (Note 17) | | 13.2 |
| | — |
| |
| Current liabilities of discontinued operations and held-for-sale businesses (Note 15) | | | 12.2 |
| | 66.9 |
|
| Total current liabilities | | 276.8 |
| | 450.9 |
| | 343.1 |
| | 276.9 |
|
| Non-current liabilities: | |
| |
| |
| |
|
| Long-term debt (Note 8) | | 1,700.4 |
| | 1,828.7 |
| |
| Deferred taxes (Note 9) | | 111.2 |
| | 252.4 |
| |
| Long-term debt (Note 7) | | | 1,372.3 |
| | 1,700.2 |
|
| Deferred taxes (Note 8) | | | 116.1 |
| | 113.5 |
|
| Taxes payable | | 77.4 |
| | 84.6 |
| | 76.1 |
| | 74.8 |
|
| Regulatory liabilities, non-current (Note 3) | | 221.2 |
| | 130.4 |
| | 278.3 |
| | 221.2 |
|
| Pension, retiree and other benefits (Note 10) | | 101.0 |
| | 101.6 |
| |
| Pension, retiree and other benefits (Note 9) | | | 82.3 |
| | 90.3 |
|
| Asset retirement obligations | | 131.2 |
| | 138.8 |
| | 9.4 |
| | 15.1 |
|
| Other deferred credits | | 14.3 |
| | 19.4 |
| | 8.0 |
| | 8.5 |
|
| Non-current liabilities of discontinued operations and held-for-sale businesses (Note 15) | | | 69.2 |
| | 133.0 |
|
| Total non-current liabilities | | 2,356.7 |
| | 2,555.9 |
| | 2,011.7 |
| | 2,356.6 |
|
| | | | | | | | | |
| Commitments and contingencies (Note 12) | |
| |
| |
| Commitments and contingencies (Note 11) | | |
| |
|
| | | | | | | | | |
| Common shareholder's deficit: | |
| |
| |
| |
|
| Common stock: | |
| |
| |
| |
|
| 1,500 shares authorized; 1 share issued and outstanding | |
| |
| |
| |
|
| at December 31, 2017 and 2016 | | — |
| | — |
| |
| at December 31, 2018 and 2017 | | | — |
| | — |
|
| Other paid-in capital | | 2,330.4 |
| | 2,233.0 |
| | 2,370.5 |
| | 2,330.4 |
|
| Accumulated other comprehensive income | | 0.8 |
| | 0.3 |
| | 2.2 |
| | 0.8 |
|
| Accumulated deficit | | (2,915.5 | ) | | (2,820.9 | ) | | (2,844.4 | ) | | (2,915.5 | ) |
| Total common shareholder's deficit: | | (584.3 | ) | | (587.6 | ) | | (471.7 | ) | | (584.3 | ) |
| | | | | | | | | |
| Total Liabilities and Shareholder's Equity | | $ | 2,049.2 |
| | $ | 2,419.2 |
| | $ | 1,883.1 |
| | $ | 2,049.2 |
|
See Notes to Consolidated Financial Statements.
| | DPL INC. | | CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| Consolidated Statements of Cash Flows | | Consolidated Statements of Cash Flows |
| | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities: | | | | | | | | | | | | |
| Net loss | | $ | (94.6 | ) | | $ | (485.2 | ) | | $ | (239.0 | ) | |
| Adjustments to reconcile Net loss to Net cash from operating activities | | | | | | | |
| Net income / (loss) | | | $ | 70.1 |
| | $ | (94.6 | ) | | $ | (485.2 | ) |
| Adjustments to reconcile Net income / (loss) to Net cash from operating activities | | | | | | | |
| Depreciation and amortization | | 106.9 |
| | 132.3 |
| | 138.8 |
| | 50.2 |
| | 106.9 |
| | 132.3 |
|
| Amortization of debt market value adjustments | | 0.1 |
| | 0.1 |
| | (1.1 | ) | |
| Amortization of deferred financing costs | | 3.6 |
| | 5.6 |
| | 5.9 |
| | 5.5 |
| | 3.6 |
| | 5.6 |
|
| Unrealized (gain) / loss on derivatives | | (1.7 | ) | | (4.3 | ) | | 5.8 |
| | (0.2 | ) | | (1.7 | ) | | (4.3 | ) |
| Deferred income taxes | | (22.2 | ) | | (306.2 | ) | | (17.1 | ) | | (9.1 | ) | | (22.2 | ) | | (306.2 | ) |
| Charge for early redemption of debt | | 3.3 |
| | 3.1 |
| | 2.1 |
| | 6.5 |
| | 3.3 |
| | 3.1 |
|
| Goodwill impairment | | — |
| | — |
| | 317.0 |
| |
| Fixed-asset impairment | | 175.8 |
| | 859.0 |
| | — |
| | 2.8 |
| | 175.8 |
| | 859.0 |
|
| Loss / (Gain) on asset disposal | | 2.2 |
| | (49.2 | ) | | 0.4 |
| |
| Loss / (Gain) on disposal and sale of business, net | | | 13.3 |
| | (14.0 | ) | | (49.2 | ) |
| Loss / (Gain) on asset disposal, net | | | (2.0 | ) | | 16.1 |
| | (0.1 | ) |
| Changes in certain assets and liabilities: | | | | | | | | | | | | |
| Accounts receivable | | 16.8 |
| | 24.2 |
| | 43.4 |
| | 45.7 |
| | 18.1 |
| | 25.6 |
|
| Inventories | | 7.7 |
| | 32.0 |
| | (9.0 | ) | | 14.8 |
| | 7.7 |
| | 32.0 |
|
| Prepaid taxes | | — |
| | 0.2 |
| | (1.3 | ) | |
| Taxes applicable to subsequent years | | 2.3 |
| | 0.2 |
| | (3.4 | ) | | 0.1 |
| | 2.3 |
| | 0.2 |
|
| Deferred regulatory costs, net | | (23.7 | ) | | 4.1 |
| | 21.8 |
| | (9.2 | ) | | (23.7 | ) | | 4.1 |
|
| Accounts payable | | (35.0 | ) | | 16.5 |
| | (5.1 | ) | | (16.3 | ) | | (36.3 | ) | | 15.1 |
|
| Accrued taxes payable | | (3.7 | ) | | 45.1 |
| | 43.8 |
| | 37.4 |
| | (3.7 | ) | | 45.1 |
|
| Accrued interest payable | | (1.3 | ) | | (3.7 | ) | | (5.7 | ) | | (2.1 | ) | | (1.3 | ) | | (3.7 | ) |
| Pension, retiree and other benefits | | 4.5 |
| | 8.6 |
| | (0.7 | ) | | (3.4 | ) | | 4.7 |
| | 3.0 |
|
| Unamortized investment tax credit | | (0.3 | ) | | (0.4 | ) | | (0.5 | ) | |
| Insurance and claims costs | | (2.4 | ) | | (0.5 | ) | | (0.5 | ) | | 1.1 |
| | (2.4 | ) | | (0.5 | ) |
| Other | | (6.6 | ) | | (14.4 | ) | | 12.9 |
| | 0.7 |
| | (6.9 | ) | | (8.8 | ) |
| Net cash provided by operating activities | | 131.7 |
| | 267.1 |
| | 308.5 |
| | 205.9 |
| | 131.7 |
| | 267.1 |
|
| Cash flows from investing activities: | | | | | | | | | | | | |
| Capital expenditures | | (121.5 | ) | | (148.5 | ) | | (137.2 | ) | | (103.6 | ) | | (121.5 | ) | | (148.5 | ) |
| Proceeds from sale of business | | 70.1 |
| | 75.5 |
| | 1.3 |
| |
| Proceeds from disposal and sale of business | | | 234.9 |
| | 70.1 |
| | — |
|
| Payments on disposal and sale of business | | | (14.5 | ) | | — |
| | — |
|
| Proceeds from sale of property | | | 10.6 |
| | 0.1 |
| | 0.2 |
|
| Insurance proceeds | | 12.3 |
| | 6.3 |
| | — |
| | 3.0 |
| | 12.3 |
| | 6.3 |
|
| Purchase of renewable energy credits | | (0.6 | ) | | (0.4 | ) | | (0.8 | ) | |
| Decrease / (increase) in restricted cash | | 27.1 |
| | (11.8 | ) | | (0.4 | ) | |
| Other investing activities, net | | 0.4 |
| | 1.1 |
| | 0.4 |
| | (0.5 | ) | | (0.3 | ) | | 0.5 |
|
| Net cash used in investing activities | | (12.2 | ) | | (77.8 | ) | | (136.7 | ) | |
| Net cash provided by / (used in) investing activities | | | 129.9 |
| | (39.3 | ) | | (141.5 | ) |
| Cash flows from financing activities: | | | | | | | | | | | | |
| Payments of deferred financing costs | | — |
| | (8.6 | ) | | (6.9 | ) | | — |
| | — |
| | (8.6 | ) |
| Redemption of preferred stock | | — |
| | (23.5 | ) | | — |
| | — |
| | — |
| | (23.5 | ) |
| Retirement of debt | | (159.5 | ) | | (577.8 | ) | | (474.5 | ) | | (240.5 | ) | | (159.5 | ) | | (577.8 | ) |
| Issuance of long-term debt, net of discount | | — |
| | 442.8 |
| | 325.0 |
| | — |
| | — |
| | 442.8 |
|
| Borrowings from revolving credit facilities | | 102.5 |
| | 15.0 |
| | 80.0 |
| | 30.0 |
| | 102.5 |
| | 15.0 |
|
| Repayment of borrowings from revolving credit facilities | | (92.5 | ) | | (15.0 | ) | | (80.0 | ) | | (40.0 | ) | | (92.5 | ) | | (15.0 | ) |
| Other financing activities, net | | (0.1 | ) | | — |
| | — |
| | — |
| | (0.1 | ) | | — |
|
| Net cash used in financing activities | | (149.6 | ) | | (167.1 | ) | | (156.4 | ) | | (250.5 | ) | | (149.6 | ) | | (167.1 | ) |
| Cash and cash equivalents: | | | | | | | |
| Net increase / (decrease) in cash | | (30.1 | ) | | 22.2 |
| | 15.4 |
| |
| Increase in cash and restricted cash of discontinued operations and held-for-sale businesses | | | 1.5 |
| | 27.5 |
| | 15.8 |
|
| Cash, cash equivalents and restricted cash: | | | | | | | . |
| Net increase / (decrease) in cash, cash equivalents and restricted cash | | | 86.8 |
| | (29.7 | ) | | (25.7 | ) |
| Balance at beginning of year | | 54.6 |
| | 32.4 |
| | 17.0 |
| | 24.9 |
| | 54.6 |
| | 80.3 |
|
| Cash and cash equivalents at end of year | | $ | 24.5 |
| | $ | 54.6 |
| | $ | 32.4 |
| |
| Cash, cash equivalents and restricted cash at end of year | | | $ | 111.7 |
| | $ | 24.9 |
| | $ | 54.6 |
|
| Supplemental cash flow information: | | | | | | | | | | | | |
| Interest paid, net of amounts capitalized | | $ | 105.2 |
| | $ | 103.8 |
| | $ | 111.6 |
| | $ | 93.7 |
| | $ | 105.2 |
| | $ | 103.8 |
|
| Income taxes paid / (refunded), net | | $ | — |
| | $ | 0.3 |
| | $ | 0.8 |
| |
| Income taxes (refunded) / paid, net | | | $ | (1.4 | ) | | $ | — |
| | $ | 0.3 |
|
| Non-cash financing and investing activities: | | | | | | | | | | | | |
| Accruals for capital expenditures | | $ | 12.9 |
| | $ | 16.2 |
| | $ | 18.6 |
| | $ | 10.4 |
| | $ | 12.9 |
| | $ | 16.2 |
|
| Non-cash capital contribution | | $ | 97.1 |
| | $ | — |
| | $ | — |
| |
| Non-cash proceeds from sale of business | | | $ | 4.1 |
| | $ | — |
| | $ | — |
|
| Non-cash capital contribution (Note 10) | | | $ | 40.0 |
| | $ | 97.1 |
| | $ | — |
|
See Notes to Consolidated Financial Statements.
| | DPL INC. | | CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY | |
| Consolidated Statements of Shareholder's Equity | | Consolidated Statements of Shareholder's Equity |
| | | Common Stock (a) | | | | | | | | | | Common Stock (a) | | | | | | | | |
| $ in millions | | Outstanding Shares | | Amount | | Other Paid-in Capital | | Accumulated Other Comprehensive Income / (Loss) | | Accumulated deficit | | Total | | Outstanding Shares | | Amount | | Other Paid-in Capital | | Accumulated Other Comprehensive Income / (Loss) | | Accumulated Deficit | | Total |
| Year ended December 31, 2016 | | | | | | | | | | | | | |
| Beginning balance | | 1 |
| | $ | — |
| | $ | 2,237.4 |
| | $ | 7.5 |
| | $ | (2,096.7 | ) | | $ | 148.2 |
| | 1 |
| | $ | — |
| | $ | 2,237.7 |
| | $ | 17.4 |
| | $ | (2,335.7 | ) | | $ | (80.6 | ) |
| Year ended December 31, 2015 | | | | | | | | | | | | | |
| Net comprehensive loss | | | | | | | | 9.9 |
| | (239.0 | ) | | (229.1 | ) | |
Other | | | | | | 0.3 |
| | | |
|
| | 0.3 |
| |
| Ending balance | | 1 |
| | — |
| | 2,237.7 |
| | 17.4 |
| | (2,335.7 | ) | | (80.6 | ) | |
| Year ended December 31, 2016 | | | | | | | | | | | | | |
| Net comprehensive loss | | | | | | | | (17.1 | ) | | (485.2 | ) | | (502.3 | ) | | | | | | | | (17.1 | ) | | (485.2 | ) | | (502.3 | ) |
Other (b) | | | | | | (4.7 | ) | | | |
|
| | (4.7 | ) | | | | | | (4.7 | ) | | | |
|
| | (4.7 | ) |
| Ending balance | | 1 |
| | — |
| | 2,233.0 |
| | 0.3 |
| | (2,820.9 | ) | | (587.6 | ) | | 1 |
| | — |
| | 2,233.0 |
| | 0.3 |
| | (2,820.9 | ) | | (587.6 | ) |
| Year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | | | | | | |
| Net comprehensive loss | | | | | | | | 0.5 |
| | (94.6 | ) | | (94.1 | ) | | | | | | | | 0.5 |
| | (94.6 | ) | | (94.1 | ) |
Other (c) | | | | | | 97.4 |
| | | |
|
| | 97.4 |
| |
Capital contributions (c) | | | | | | | 97.1 |
| | | | | | 97.1 |
|
| Other | | | | | | | 0.3 |
| | | |
|
| | 0.3 |
|
| Ending balance | | 1 |
| | $ | — |
| | $ | 2,330.4 |
| | $ | 0.8 |
| | $ | (2,915.5 | ) | | $ | (584.3 | ) | | 1 |
| | — |
| | 2,330.4 |
| | 0.8 |
| | (2,915.5 | ) | | (584.3 | ) |
| Year ended December 31, 2018 | | | | | | | | | | | | | |
| Net comprehensive income | | | | | | | | | 2.4 |
| | 70.1 |
| | 72.5 |
|
Capital contributions (c) | | | | | | | 40.0 |
| | | | | | 40.0 |
|
Other (d) | | | | | | | 0.1 |
| | (1.0 | ) | | 1.0 |
| | 0.1 |
|
| Ending balance | | | 1 |
| | $ | — |
| | $ | 2,370.5 |
| | $ | 2.2 |
| | $ | (2,844.4 | ) | | $ | (471.7 | ) |
| |
| (a) | 1,500 shares authorized. |
| |
| (b) | Includes $5.1 million charged to Other paid-in capital for the redemption of the DP&L preferred shares. See Note 1110 – Equity. |
| |
| (c) | IncludesRepresents the conversion of a $97.1 million tax sharing payable to AES conversion to contributed capital, as DP&L's 2017 ESP restricts tax sharing payments to AES during the term of the ESP. See Note 98 – 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. |
See Notes to Consolidated Financial Statements.
DPL Inc.
Notes to Consolidated Financial Statements
For the years ended December 31, 2018, 2017 2016 and 20152016
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 twoone reportable segments,segment, the Transmission and Distribution ("T&D") segment and the Generation segment.Utility segment. See Note 1413 – Business Segments for more information relating to our reportable segments.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 521,000525,000 customers located in West Central Ohio. DP&L is required to procure and provideprovides 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 100%all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in fivemultiple 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.
DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations. See Note 16 – Discontinued Operations for more information.
DPL’s other significantprimary subsidiaries include MVIC and AES Ohio Generation, which owns and operates coal-fired and peaking generating facilities from which it makes wholesale sales of electricity, andGeneration. MVIC is our captive insurance company that provides insurance services to us and our other subsidiaries. DPL whollyand our subsidiaries. AES Ohio Generation owns eachan undivided interest in Conesville Unit 4. AES Ohio Generation sells all of its subsidiaries.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 December 15, 2017,March 27, 2018, DPL and AES Ohio Generation entered into an asset purchase agreement forcompleted the sale of itstheir 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.costs or overcollections of riders.
DPL and its subsidiaries employed 1,060659 people at January 31, 2018,2019, of which 660647 were employed by DP&L&L. . Approximately 60%57% of all DPL employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and
DP&L and AES Ohio Generation each have the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted.
Financial Statement Presentation
We prepare Consolidated Financial Statements for DPL. 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 hashad undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities arewere 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; and intangibles.benefits.
Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidenceRevenue is recognized upon transfer of an arrangement exists, the productscontrol of promised goods or services have been provided to customers in an amount that reflects the customer, the sales price is fixedconsideration to which we expect to be entitled in exchange for those goods or determinable, and collection is reasonably assured.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 stationsstation is sold to an RTO. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.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 stationsstation as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.3$0.5 million, $2.8$1.7 million and $2.0$2.1 million in the years ended December 31, 2018, 2017 and 2016, and 2015, 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. See Note 15 – Fixed-asset Impairments for more information.
Repairs and Maintenance
Costs associated with maintenance activities primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 4.3% in 2018, 5.0% in 2017 and 6.1% in 2016 (including property classified in non-current assets of discontinued operations and 4.4%held-for-sale businesses in 2015.2017 and 2016). Depreciation expense was $100.1$66.5 million, $124.6$70.4 million and $125.6$67.0 million for the years ended December 31, 2018, 2017 2016 and 2015,2016, 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 oil and gas used for electric generation, and materials and supplies used for utility operations.
Intangibles
Intangibles include software, emission allowances and renewable energy credits. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess
emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are carried on a weighted average cost basis and amortized as they are used or retired.
Software is amortized over seven years.years A. mortizationAmortization expense was $6.8$6.6 million, $7.7$5.7 million and $9.0$6.6 million for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. The estimated amortization expense of this internal-use software over the next five years is $17.2$15.0 million ($7.2 million in 2018, $4.24.2 million in 2019, $2.7$3.2 million in 2020, $1.7$3.0 million in 2021, and $1.4$2.6 million in 2022)2022 and $2.0 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 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.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 98 – Income Taxes for additional information.
Financial Instruments
We classify ourOur Master Trust investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-saleare classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on thosethese securities netare recorded in Other income. As these financial instruments are held to be used for the benefit of deferred income taxes,employees participating in employee benefit plans and are presented as a separate component of shareholder's equity. Other-than-temporary declines in valuenot used for general operating purposes, they are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.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 livedlong-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 1715 – Assets and Liabilities Held-For-Sale and DispositionsDiscontinued Operations for further information.
Discontinued Operations
Discontinued operations reporting occurs only when the disposal of a business or a group of businessesassets 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 1615 – 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, and 2015, were $51.7 million, $49.4 million $50.9 million and $49.9$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:
|
| | | | | | | | |
| $ in millions | | December 31, 2018 | | December 31, 2017 |
| Cash and cash equivalents | | $ | 90.5 |
| | $ | 24.5 |
|
| Restricted cash | | 21.2 |
| | 0.4 |
|
| 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 forward contractsinterest rate hedges to reduce our exposure to changes in energy and commodity prices and as a hedge againstmanage the interest rate risk of changes in cash flows associated with expected electricity purchases. We hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability.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 and, in some cases, our partners in commonly-owned facilities we operate, 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 $3.0$4.1 million and $5.4$3.0 million at December 31, 20172018 and 2016,2017, 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 $11.9$4.3 million and $10.9$4.4 million at December 31, 20172018 and 2016,2017, 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 in the funded status,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.
Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of FASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.
See Note 109 – 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 1312 – Related Party Transactions for more information on Related Party Transactions.
DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidatedan unconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3$0.2 million and $0.3 million at December 31, 20172018 and 2016,2017, 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, 20172018 and December 31, 2016,2017, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 87 – DebtLong-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.
New accounting pronouncements adopted in 2018
The following table provides a brief description of recentrecently adopted accounting pronouncements that couldhad 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:statements.
|
| | | |
| Accounting Standard | Description | Date of Adoption | Effect on the financial statements upon adoption |
| New Accounting Standards Adopted |
2016-09,2018-15, 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. | October 1, 2018 | 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. | Early adoption elected, January 1, 2018 | Impact limited to changes in financial statement disclosures. |
2017-07, Compensation - Stock CompensationRetirement Benefits (Topic 718)715): ImprovementsImproving 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. | January 1, 2018 | For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Employee Share-Based Payment AccountingOther 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) | TheThis standard simplifiesrequires that a statement of cash flows explain the following aspectschange during the period in the total of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefitscash, 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, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes.flows.
Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.retrospective. | January 1, 2017.2018 | 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 recognitionstandard significantly revises an entity’s accounting related to (1) classification and measurement of excess tax benefitsinvestments in our provisionequity securities and (2) the presentation of certain fair value changes for income taxes infinancial 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. | January 1, 2018 | 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) | See discussion of the period whenASU below. | January 1, 2018 | See impact upon adoption of the awards vest or are settled, rather than in paid-in-capitalstandard below. |
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 period when the excess tax benefits are realized.financial statements upon adoption |
New Accounting Standards Issued Butbut 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. | January 1, 2019. Early adoption is permitted. | We are currently evaluating thedo not expect any impact of adopting the standard on our consolidated financial statements.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.
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. | January 1, 2019. Early adoption is permitted. | We are currently evaluating the impact of adopting the standard on our consolidated financial statements. |
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities | This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date.
Transition method: modified retrospective. | January 1, 2019. Early adoption is permitted. | We are currently evaluating the impact of adopting the standard on our consolidated financial statements. |
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 cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. | January 1, 2018. | We expect the adoption of this standard to result in a reclassification of non-service pension costs from Operating expenses to Other expense of $1.9 million and $1.8 million in 2017 and 2016, respectively. |
|
| | | |
Accounting Standard | Description | Date of Adoption | Effect on the financial statements upon adoption |
2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) | This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.
Transition method: retrospective. | January 1, 2018 | We expect the adoption of this standard to result in a reclassification from "Net cash used in investing activities" to "Net increase / (decrease) in cash" of $27.1 million and ($11.8) million in 2017 and 2016, respectively. |
2018-19, 2016-13, Financial Instruments-CreditInstruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments | The standard updates the impairment model for financial assets measured at amortized costcost. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to an expected lossuse a new forward-looking "expected loss" model rather than an incurred loss model. It also allowsthat generally will result in the earlier recognition of allowance for the presentation oflosses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses on available-for-sale debt securitiesas it is done today, except that the losses will be recognized as an allowance rather than a write down.
reduction in the amortized cost of the securities. Transition method: various. | January 1, 2020. Early adoption is permitted only as of January 1, 2019. | We are currently evaluating the impact of adopting the standard on our consolidated financial statements. |
2016-02, 2018-01, 2018-10, 2018-11, 2018-20
Leases (Topic 842) | See discussion of the ASU below. | January 1, 2019. Early adoption is permitted. | We are currently evaluating the impact of adoptinghave adopted the standard on our consolidated financial statements. |
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, Revenue from Contracts with Customers (Topic 606) | See discussion of the ASUs below. | January 1, 2018. | We will adopt the standards on January 1, 2018;2019; see below for the evaluation of the impact of its adoption on theour consolidated financial statements. |
ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transferAdoption of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard replaces most existing revenue recognition guidance in GAAP.
The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application.
In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.
We are assessing the standard on a contract-by-contract basis applying the interpretations reached during 2017 on key issues. This includes the application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, we have been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, we have not identified any situations where revenue recognized under FASC 606 could differ from that recognized under FASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, we expect to use the modified retrospective approach.
We are continuing to work with various non-authoritative industry groups and continue to monitor the FASB and Transition Resource Group activity as we finalize our accounting policy on these and other industry-specific interpretive issues.
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,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 requiresmust be adopted using a modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).approach. The FASB proposed amending the standard to give another option for transition. The proposedhas provided an optional transition method, would allowwhich we have elected, that allows entities to notcontinue to apply the new lease standardguidance in FASC 840 Leases to the comparative periods presented in their financial statements in the year of adoption. Under the proposedthis transition method, the entity wouldwe will apply the transition provisions starting on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election2019.
We have elected to apply a package of practical expedients that allow themlessees 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. Furthermore, entities are also permitted to make an election to use hindsight when determining lease term and entities can elect to use hindsight when assessing the impairment of right-of-use assets.
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 assetassets and related liability.liabilities. Additionally, the implementation team has been working on the identification and selectionconfiguration of a lease accounting systemtool that wouldwill support the implementation and the subsequent accounting. The implementation team is in the process of evaluatinghas also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern is not expected to change.
Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today'sthe 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 that dependsuch as margin on the usesale of the asset (e.g. Mwh produced by a facility).energy. Therefore, the lease receivable could be lowersignificantly 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 selling gain/loss at lease commencement. We are assessing situations for which this guidance would apply.
The adoption of FASC 842 did not have a material impact on our consolidated financial statements.
Note 2 – Supplemental Financial Information
| | | | | December 31, | | December 31, |
| $ in millions | | 2017 | | 2016 | | 2018 | | 2017 |
| Accounts receivable, net | | | | | | | | |
| Customer receivables | | | $ | 55.8 |
| | $ | 45.2 |
|
| Unbilled revenue | | $ | 18.0 |
| | $ | 43.0 |
| | 16.8 |
| | 18.0 |
|
| Customer receivables | | 57.8 |
| | 73.9 |
| |
| Amounts due from partners in jointly-owned stations | | 19.1 |
| | 12.7 |
| |
Due from PJM transmission enhancement settlement (a) | | | 16.5 |
| | — |
|
| Other | | 4.9 |
| | 6.7 |
| | 2.3 |
| | 2.5 |
|
| Provisions for uncollectible accounts | | (1.1 | ) | | (1.2 | ) | | (0.9 | ) | | (1.1 | ) |
| Total accounts receivable, net | | $ | 98.7 |
| | $ | 135.1 |
| | $ | 90.5 |
| | $ | 64.6 |
|
| | | | | | | | | |
| Inventories, at average cost | | | | | | | | |
| Fuel and limestone | | $ | 15.5 |
| | $ | 38.9 |
| | $ | 1.9 |
| | $ | 4.1 |
|
| Plant materials and supplies | | 8.5 |
| | 36.6 |
| |
| Materials and supplies | | | 8.3 |
| | 8.1 |
|
| Other | | 0.5 |
| | 1.7 |
| | 0.5 |
| | 0.5 |
|
| Total inventories, at average cost | | $ | 24.5 |
| | $ | 77.2 |
| | $ | 10.7 |
| | $ | 12.7 |
|
(a) - See Note 3 – Regulatory Matters for more information.
Accumulated Other Comprehensive Income / (Loss)
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2018, 2017 2016 and 20152016 are as follows:
| | | Details about Accumulated Other Comprehensive Income / (Loss) Components | | Affected line item in the Consolidated Statements of Operations | | Years ended December 31, | | Affected line item in the Consolidated Statements of Operations | | Years ended December 31, |
| $ in millions | | | | 2017 | | 2016 | | 2015 | | | | 2018 | | 2017 | | 2016 |
| Gains and losses on Available-for-sale securities activity (Note 5): | | | | | | | |
| Gains and losses on equity securities (Note 5): | | Gains and losses on equity securities (Note 5): | | | | | | |
| | | Other deductions | | $ | (0.1 | ) | | $ | — |
| | $ | — |
| | Other deductions | | $ | — |
| | $ | (0.1 | ) | | $ | — |
|
| | | Income tax expense / (benefit) from continuing operations | | — |
| | — |
| | — |
| | Income tax expense | | — |
| | — |
| | — |
|
| | | Net of income taxes | | (0.1 | ) | | — |
| | — |
| | Net of income taxes | | — |
| | (0.1 | ) | | — |
|
| | | | | | | | | | | | | |
| Gains and losses on cash flow hedges (Note 6): | Gains and losses on cash flow hedges (Note 6): | | | | | | | Gains and losses on cash flow hedges (Note 6): | | | | | | |
| | | Interest expense | | (1.0 | ) | | (1.0 | ) | | (1.1 | ) | | Interest expense | | (1.2 | ) | | (1.0 | ) | | (1.0 | ) |
| | | Revenues | | (15.2 | ) | | (55.3 | ) | | (18.7 | ) | | Income tax benefit | | 0.4 |
| | 0.3 |
| | 0.5 |
|
| | | Net purchased power cost | | 3.8 |
| | 9.9 |
| | 4.4 |
| | Net of income taxes | | (0.8 | ) | | (0.7 | ) | | (0.5 | ) |
| | | Total before income taxes | | (12.4 | ) | | (46.4 | ) | | (15.4 | ) | | | | | | |
| | | Income tax expense / (benefit) from continuing operations | | 4.4 |
| | 16.7 |
| | 5.4 |
| | Gain / (loss) from discontinued operations | | 4.4 |
| | (11.4 | ) | | (45.4 | ) |
| | | Net of income taxes | | (8.0 | ) | | (29.7 | ) | | (10.0 | ) | | 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 10): | | | | | | | |
| | | | | | | | |
| Amortization of defined benefit pension items (Note 9): | | Amortization of defined benefit pension items (Note 9): | | | | | | |
| | | Operation and maintenance | | 1.5 |
| | 1.6 |
| | 0.4 |
| | Other income | | 0.8 |
| | 1.5 |
| | 1.6 |
|
| | | Income tax expense / (benefit) from continuing operations | | (0.5 | ) | | (0.6 | ) | | (0.2 | ) | | Income tax expense | | (0.2 | ) | | (0.5 | ) | | (0.6 | ) |
| | | Net of income taxes | | 1.0 |
| | 1.0 |
| | 0.2 |
| | Net of income taxes | | 0.6 |
| | 1.0 |
| | 1.0 |
|
| | | | | | | | | | | | | |
| Total reclassifications for the period, net of income taxes | Total reclassifications for the period, net of income taxes | | $ | (7.1 | ) | | $ | (28.7 | ) | | $ | (9.8 | ) | 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, 20172018 and 20162017 are as follows:
| | | $ in millions | | Gains / (losses) on available-for-sale securities | | Gains / (losses) on cash flow hedges | | Change in unfunded pension obligation | | Total | | Gains / (losses) on equity securities | | Gains / (losses) on cash flow hedges | | Change in unfunded pension obligation | | Total |
| Balance at December 31, 2015 | | $ | 0.4 |
| | $ | 26.7 |
| | $ | (9.7 | ) | | $ | 17.4 |
| |
| | | | | | | | | | |
| Other comprehensive income / (loss) before reclassifications | | 0.2 |
| | 16.1 |
| | (4.7 | ) | | 11.6 |
| |
| Amounts reclassified from accumulated other comprehensive income / (loss) | | — |
| | (29.7 | ) | | 1.0 |
| | (28.7 | ) | |
| Net current period other comprehensive income / (loss) | | 0.2 |
| | (13.6 | ) | | (3.7 | ) | | (17.1 | ) | |
| | | | | | | | | | |
| Balance at December 31, 2016 | | 0.6 |
| | 13.1 |
| | (13.4 | ) | | 0.3 |
| | $ | 0.6 |
| | $ | 13.1 |
| | $ | (13.4 | ) | | $ | 0.3 |
|
| | | | | | | | | | | | | | | | | |
| Other comprehensive income / (loss) before reclassifications | | 0.5 |
| | 9.6 |
| | (2.5 | ) | | 7.6 |
| | 0.5 |
| | 9.6 |
| | (2.5 | ) | | 7.6 |
|
| Amounts reclassified from accumulated other comprehensive income / (loss) | | (0.1 | ) | | (8.0 | ) | | 1.0 |
| | (7.1 | ) | | (0.1 | ) | | (8.0 | ) | | 1.0 |
| | (7.1 | ) |
| Net current period other comprehensive income / (loss) | | 0.4 |
| | 1.6 |
| | (1.5 | ) | | 0.5 |
| | 0.4 |
| | 1.6 |
| | (1.5 | ) | | 0.5 |
|
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2017 | | $ | 1.0 |
| | $ | 14.7 |
| | $ | (14.9 | ) | | $ | 0.8 |
| | 1.0 |
| | 14.7 |
| | (14.9 | ) | | 0.8 |
|
| | | | | | | | | | |
| Other comprehensive loss before reclassifications | | | — |
| | (0.1 | ) | | (0.5 | ) | | (0.6 | ) |
| Amounts reclassified from accumulated other comprehensive income to earnings | | | — |
| | 2.4 |
| | 0.6 |
| | 3.0 |
|
| Net current period other comprehensive income | | | — |
| | 2.3 |
| | 0.1 |
| | 2.4 |
|
| | | | | | | | | | |
Amounts reclassified from accumulated other comprehensive income to accumulated deficit (a) | | | (1.0 | ) | | — |
| | — |
| | (1.0 | ) |
| | | | | | | | | | |
| Balance at December 31, 2018 | | | $ | — |
| | $ | 17.0 |
| | $ | (14.8 | ) | | $ | 2.2 |
|
Operating expenses - other
Operating expenses - other generally includes gains or losses on asset sales or dispositions, insurance recoveries, gains or losses on the sale of businesses and other expense or income from miscellaneous transactions. The components are summarized as follows:
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 |
| Write-off of plant materials and supplies inventories | | $ | 16.2 |
| | $ | — |
| | $ | — |
|
| Gain on sale of business | | (14.0 | ) | | — |
| | — |
|
| Insurance recoveries | | (8.7 | ) | | (0.7 | ) | | — |
|
| Loss / (gain) on disposition of property | | — |
| | (0.1 | ) | | 0.4 |
|
| Other | | (0.1 | ) | | 0.7 |
| | — |
|
| Net other expense / (income) | | $ | (6.6 | ) | | $ | (0.1 | ) | | $ | 0.4 |
|
| |
| (a) | 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 JanuaryDecember 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 a settlement inan amended stipulation to its 2017 ESP, case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The six-year 2017 ESP establishes DP&L's framework for providing retail service on a going forwardgoing-forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory parties agreed to a six-year settlement that provides a framework for energy rates and defines componentsmechanisms 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;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 is to bewas established in a separatethe DP&L distribution rate case;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 98 – Income Taxes and Note 1110 – Equity for more information on the tax sharing payment restrictions; and
Various other riders and competitive retail market enhancements.
In connection with any sale or closureOn October 19, 2018 IGS, a retail electricity supplier, filed a Notice of our generation plants, DPL expectsWithdrawal 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 incur certain cash and non-cash charges, some or all of which could be material to the business and financial condition of DPLbegin April 1, 2019.
As part of Additionally, on January 7, 2019, the normal review and approval process, the PUCO‘s order approvingOhio Consumers' Counsel appealed the 2017 ESP settlementOrder to the Supreme Court of Ohio. That appeal is subject to rehearing requests. Several parties, including DP&L, applied for a rehearing. Those rehearing applications are still 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. AOn October 22, 2018, a stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the2016 or 2017. That stipulation is pending PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending.approval. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows.
The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. We are not able at this time to predict the impact of this proceeding on our business, financial condition or results of operations.
Impact of tax reformTax 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 paymentspayments. 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 ifany 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&L’s rates are reducedwere 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, our cash flows could be adversely affected. It is too earlyresulting 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 whetherthe amount of excess deferred income taxes caused by the TCJA. DP&L is unable to predict the outcome of this proceedingnotice or the impact it may have a material impact 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&L’s business, financial conditiontransmission 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 results of operations.net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018.
Regulatory assetsAssets and liabilitiesLiabilities
In accordance with FASC 980, we have recognized total regulatory assets of $187.1$193.7 million and $204.0$187.1 million at December 31, 20172018 and 2016,2017, respectively, and total regulatory liabilities of $236.0$313.2 million and $164.1$236.0 million at December 31, 20172018 and 2016,2017, respectively. Regulatory assets and liabilities are classified as current or non-
currentnon-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, | | Type of Recovery | | Amortization Through | | December 31, |
| $ in millions | | 2017 | | 2016 | | 2018 | | 2017 |
| Regulatory assets, current: | | | | | | | | | | | | | | | | |
| Undercollections to be collected through rate riders | | A/B |
| 2018 | | $ | 23.9 |
| | $ | 0.1 |
| | A/B |
| 2019 | | $ | 40.5 |
| | $ | 23.9 |
|
| Rate case expenses being recovered in base rates | | | B | | 2019 | | 0.6 |
| | — |
|
| Total regulatory assets, current | |
| | 23.9 |
| | 0.1 |
| |
| | 41.1 |
| | 23.9 |
|
| | | | | | | | | |
| Regulatory assets, non-current: | |
| | | | | |
| | | | |
| Pension benefits | | B |
| Ongoing | | 92.4 |
| | 97.6 |
| | B |
| Ongoing | | 87.5 |
| | 92.4 |
|
| Deferred recoverable income taxes | | B/C |
| Ongoing | | — |
| | 35.9 |
| |
| Unrecovered OVEC charges | | D |
| Undetermined | | 27.8 |
| | 21.0 |
| | C |
| Undetermined | | 28.7 |
| | 27.8 |
|
| Fuel costs | | B |
| 2020 | | 9.3 |
| | 15.4 |
| | B |
| 2020 | | 3.3 |
| | 9.3 |
|
| Regulatory compliance costs | | B |
| 2020 | | 9.2 |
| | 12.4 |
| | B |
| 2020 | | 6.1 |
| | 9.2 |
|
| Rate case costs | | B |
| Undetermined | | 8.1 |
| | 6.3 |
| |
| Smart grid and AMI costs | | B |
| Undetermined | | 7.3 |
| | 7.3 |
| | B |
| Undetermined | | 8.5 |
| | 7.3 |
|
| Unamortized loss on reacquired debt | | B |
| Various | | 7.0 |
| | 8.0 |
| | B |
| Various | | 6.0 |
| | 7.0 |
|
| Deferred storm costs | | A |
| Undetermined | | 2.1 |
| | — |
| | A |
| Undetermined | | 4.7 |
| | 2.1 |
|
| Deferred vegetation management and other | | | A/B | | Undetermined | | 7.8 |
| | 8.1 |
|
| Total regulatory assets, non-current | |
| | 163.2 |
| | 203.9 |
| |
| | 152.6 |
| | 163.2 |
|
| | |
| | | | | |
| | | | |
| Total regulatory assets | |
| | $ | 187.1 |
| | $ | 204.0 |
| |
| | $ | 193.7 |
| | $ | 187.1 |
|
| | |
| | | | | |
| | | | |
| Regulatory liabilities, current: | |
| | | | | |
| | | | |
| Overcollection of costs to be refunded through rate riders | | A/B |
| 2018 | | $ | 14.8 |
| | $ | 33.7 |
| | A/B |
| 2019 | | $ | 34.9 |
| | $ | 14.8 |
|
| Total regulatory liabilities, current | |
| | 14.8 |
| | 33.7 |
| |
| | 34.9 |
| | 14.8 |
|
| | | | | | |
| Regulatory liabilities, non-current: | |
| | | | | |
| | | | |
| Estimated costs of removal - regulated property | |
| Not Applicable | | 132.8 |
| | 126.5 |
| |
| Not Applicable | | 139.1 |
| | 132.8 |
|
| Deferred income taxes payable through rates | |
| Various | | 83.4 |
| | — |
| |
| Various | | 116.3 |
| | 83.4 |
|
| PJM transmission enhancement settlement | | | A | | 2025 | | 16.9 |
| | — |
|
| Postretirement benefits | | B |
| Ongoing | | 5.0 |
| | 3.9 |
| | B |
| Ongoing | | 6.0 |
| | 5.0 |
|
| Total regulatory liabilities, non-current | |
| | 221.2 |
| | 130.4 |
| |
| | 278.3 |
| | 221.2 |
|
| | |
| | | | | |
| | | | |
| Total regulatory liabilities | |
| | $ | 236.0 |
| | $ | 164.1 |
| |
| | $ | 313.2 |
| | $ | 236.0 |
|
A – Recovery of incurred costs plus rate of return.
B – Recovery of incurred costs without a rate of return.
C – Balance has an offsetting liability resulting in no effect on rate base.
D – 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 $12.5$5.5 million of this net deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) certain transmission related costs,decoupling rider (see above), (iii) uncollectible rider and (iii) declines in net revenues resulting from implementation of(iv) energy efficiency programs.rider. It also includes the current portion of the following deferred costs which are described in greater detail below: unbilled fuel, Regulatory Compliance Riderregulatory 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 (v) uncollectible(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 costsrider representrepresents 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. The majority of theseThese costs are being recovered over the three-years beginning November 1, 2017. Recovery of a small portion of the Generation Separation costs, including ongoing costs, will be sought in a future proceeding.three-year period.
Rate case costs represents costs associated with preparing a distribution rate case and ESP.case. DP&L has requestedwas granted recovery of these costs which do not earn a return, as part of its pending distribution rate case filing.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. This plan is currently under development and we plan to seekDP&L requested recovery of these deferred costs which currently do not earn a return, in a regulatory rate proceeding inas part of the near future. Based onDecember 2018 DMP filing with the PUCO precedent, we believe these costs are probable of future recovery in rates.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 20162017 and 2017.2018. 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 filedplans to recover 2016file petitions seeking recovery of each calendar year of storm costs on February 2, 2018 and expects to file to recover 2017 costs later in 2018.the following calendar year. Recovery of these costs is probable by 2019,2020, 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 to customersthrough rates represent deferred income tax assetsliabilities 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. The 2016 regulatory asset of $35.9 million represents the portion of DP&L’s deferred income tax asset that we believed would be recovered through future rates, without interest, based upon established regulatory practices. That 2016 asset was based upon an expected future federal income tax rate of 35%. 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 theirits 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 related regulatory asset became a $83.4 million regulatory liability.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, 20172018 and 2016:2017:
| | | | | December 31, 2017 | | December 31, 2016 | | December 31, 2018 | | December 31, 2017 |
| $ in millions | | | | Composite Rate | | | | Composite Rate | | | | Composite Rate | | | | Composite Rate (a) |
| Regulated: | | | | | | | | | | |
| Transmission | | $ | 242.7 |
| | 4.0% | | $ | 247.3 |
| | 3.9% | | $ | 223.2 |
| | 4.1% | | $ | 242.7 |
| | 4.0% |
| Distribution | | 1,197.5 |
| | 4.9% | | 1,141.1 |
| | 4.7% | | 1,289.8 |
| | 4.5% | | 1,197.5 |
| | 4.9% |
| General | | 13.7 |
| | 7.1% | | 13.7 |
| | 7.4% | | 13.2 |
| | 8.5% | | 13.7 |
| | 7.1% |
| Non-depreciable | | 64.7 |
| | N/A | | 63.5 |
| | N/A | | 60.4 |
| | N/A | | 64.7 |
| | N/A |
| Total regulated | | 1,518.6 |
| | 1,465.6 |
| | | 1,586.6 |
| | 1,518.6 |
| |
| Unregulated: | | | | | | | | | | |
| Production / Generation | | 10.9 |
| | 63.2% | | 483.2 |
| | 11.7% | | — |
| | N/A | | 0.2 |
| | N/A |
| Other | | 19.4 |
| | 7.0% | | 17.0 |
| | 8.0% | | 21.2 |
| | 6.7% | | 21.1 |
| | 7.0% |
| Non-depreciable | | 5.8 |
| | N/A | | 19.8 |
| | N/A | | 7.8 |
| | N/A | | 4.2 |
| | N/A |
| Total unregulated | | 36.1 |
| | 520.0 |
| | | 29.0 |
| | 25.5 |
| |
| | | | | | | | | | | |
| Total property, plant and equipment in service | | $ | 1,554.7 |
| | 5.0% | | $ | 1,985.6 |
| | 6.1% | | $ | 1,615.6 |
| | 4.3% | | $ | 1,544.1 |
| | 5.0% |
Coal-fired facilities
DPL and certain other Ohio utilities have undivided ownership interests in three coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. DPL’s share of the operations of such facilities is included within the corresponding line in the Consolidated Statements of Operations, and DPL’s share of the investment in the facilities is included within Total net property, plant and equipment in the Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.
DPL’s undivided ownership interest in such facilities at December 31, 2017, is as follows:
|
| | | | | | | | | | | | | | | | | |
| | | DPL Share | | DPL Carrying Value |
| | | Ownership (%) | | Summer Production Capacity (MW) | | Gross Plant In Service ($ in millions) | | Accumulated Depreciation ($ in millions) | | Construction Work in Process ($ in millions) |
| Jointly-owned production units | | | | | | | | | | |
| Conesville - Unit 4 | | 16.5 | | 129 |
| | $ | 0.7 |
| | $ | 0.7 |
| | $ | 1.9 |
|
| Killen - Unit 2 | | 67.0 | | 402 |
| | 9.6 |
| | 8.2 |
| | — |
|
| Stuart - Units 2 through 4 | | 35.0 | | 606 |
| | 1.8 |
| | 1.8 |
| | — |
|
| Transmission (at varying percentages) | | | | | | 45.6 |
| | 13.3 |
| | — |
|
| Total | | | | 1,137 |
| | $ | 57.7 |
| | $ | 24.0 |
| | $ | 1.9 |
|
Each of the above generating units has SCR and FGD equipment installed.
On January 10, 2017, a high-pressure feedwater heater shell failed on Unit 1 at the J.M. Stuart station. The unit was retired on October 1, 2017. Accordingly, DPL's 202 MWs of capacity associated with Stuart Unit 1 have been removed from the table above.
DPL announced during 2017 that it plans on retiring the co-owned Stuart Station coal-fired and diesel-fired generating units and the co-owned Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018, and the co-owners of these facilities agreed with this plan of retirement.
On December 8, 2017, AES Ohio Generation completed the sale of the Miami Fort and Zimmer EGUs.
| |
| (a) | 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 fourth quarter transaction. This transaction also resulted in cash proceeds to DP&L of 2017, DPL entered into an agreement to sell its Peaker assets. See Note 17 – Assets$10.6 million and Liabilities Held-For-Sale and Dispositions for more information.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 Other deferred creditsAsset 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.
Changes in the Liability for Generation AROs
| | | $ in millions | | |
| Balance at December 31, 2015 | $ | 65.9 |
| |
| Calendar 2016 | | |
| Additions | 70.2 |
| |
| Accretion expense | 2.7 |
| |
| Settlements | — |
| |
| Balance at December 31, 2016 | 138.8 |
| $ | 15.0 |
|
| Calendar 2017 | | |
| Additions | 0.1 |
| |
| Revisions to cash flow and timing estimates | (6.3 | ) | (0.1 | ) |
| Accretion expense | 3.7 |
| 0.4 |
|
| Settlements | (0.1 | ) | (0.2 | ) |
| Reductions due to plants sold or held-for-sale | (5.0 | ) | |
| Balance at December 31, 2017 | $ | 131.2 |
| 15.1 |
|
| Calendar 2018 | | |
| Revisions to cash flow and timing estimates | | (2.6 | ) |
| Accretion expense | | 0.3 |
|
Settlements (a) | | (3.4 | ) |
| Balance at December 31, 2018 | | $ | 9.4 |
|
| |
| (a) | 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 additions.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 $132.8$139.1 million and $126.5$132.8 million in estimated costs of removal at December 31, 20172018 and 2016,2017, 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
| | | $ in millions | | |
| Balance at December 31, 2015 | $ | 121.8 |
| |
| Calendar 2016 | | |
| Additions | 11.7 |
| |
| Settlements | (7.0 | ) | |
| Balance at December 31, 2016 | 126.5 |
| $ | 126.5 |
|
| Calendar 2017 | | |
| Additions | 12.0 |
| 12.0 |
|
| Settlements | (5.7 | ) | (5.7 | ) |
| Balance at December 31, 2017 | $ | 132.8 |
| 132.8 |
|
| Calendar 2018 | | |
| Additions | | 14.3 |
|
| Settlements | | (8.0 | ) |
| Balance at December 31, 2018 | | $ | 139.1 |
|
Note 5 – Fair Value
The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.
The table below presents the fair value and cost of our non-derivative instruments at December 31, 20172018 and 2016.2017. See Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
| | | | | December 31, 2017 | | December 31, 2016 | | December 31, 2018 | | December 31, 2017 |
| $ in millions | | Cost | | Fair Value | | Cost | | Fair Value | | Cost | | Fair Value | | Cost | | Fair Value |
| Assets | | | | | | | | | | | | | | | | |
| Money market funds | | $ | 0.3 |
| | $ | 0.3 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.3 |
| | $ | 0.3 |
|
| Equity securities | | 2.5 |
| | 4.2 |
| | 2.4 |
| | 3.4 |
| | 2.4 |
| | 3.5 |
| | 2.5 |
| | 4.2 |
|
| Debt securities | | 4.3 |
| | 4.3 |
| | 4.4 |
| | 4.4 |
| | 4.1 |
| | 4.0 |
| | 4.3 |
| | 4.3 |
|
| Hedge funds | | 0.1 |
| | 0.2 |
| | — |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.2 |
|
| Real estate | | — |
| | — |
| | 0.3 |
| | 0.3 |
| |
| Tangible assets | | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
|
| Total assets | | $ | 7.3 |
| | $ | 9.1 |
| | $ | 7.6 |
| | $ | 8.7 |
| | $ | 7.1 |
| | $ | 8.1 |
| | $ | 7.3 |
| | $ | 9.1 |
|
| | | | | | | | | | | | | | | | | |
| | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| Liabilities | | | | | | | | | | | | | | | | |
Long-term debt (a) | | $ | 1,704.8 |
| | $ | 1,819.3 |
| | $ | 1,858.4 |
| | $ | 1,907.7 |
| |
| Long-term debt | | | $ | 1,475.9 |
| | $ | 1,519.6 |
| | $ | 1,704.8 |
| | $ | 1,819.3 |
|
| |
(a) | Amounts exclude immaterial capital lease obligations |
Fair value hierarchyValue Hierarchy
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
Level 1 (quoted prices in active markets for identical assets or liabilities);
Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or
Level 3 (unobservable inputs 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 betweenamong Level 1, and Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 20172018 and 2016.2017.
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 assetsTrust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans.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. Any unrealized gains or losses are recorded in AOCI until the securities are sold.
DPL had $1.6 million ($1.0 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2017, and $1.0 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2016.
During the year ended December 31, 2017, $0.92018, $0.5 million ($0.60.4 million after tax) of various investments were sold to facilitate the distribution of benefits. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.
The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DPL was determined as follows:
| | | Assets and Liabilities at Fair Value | |
| $ in millions | | | Fair Value at December 31, 2018 (a) | | Fair Value at December 31, 2017 (a) |
| | | | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| $ in millions | | Fair Value at December 31, 2017 (a) | | Based on
Quoted Prices in
Active Markets | | Other
observable
inputs | | Unobservable inputs | |
| Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Master trust assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Money market funds | | $ | 0.3 |
| | $ | 0.3 |
| | $ | — |
| | $ | — |
| | $ | 0.4 |
| | $ | — |
| | $ | — |
| | $ | 0.4 |
| | $ | 0.3 |
| | $ | — |
| | $ | — |
| | $ | 0.3 |
|
| Equity securities | | 4.2 |
| | — |
| | 4.2 |
| | — |
| | — |
| | 3.5 |
| | — |
| | 3.5 |
| | — |
| | 4.2 |
| | — |
| | 4.2 |
|
| Debt securities | | 4.3 |
| | — |
| | 4.3 |
| | — |
| | — |
| | 4.0 |
| | — |
| | 4.0 |
| | — |
| | 4.3 |
| | — |
| | 4.3 |
|
| Hedge funds | | 0.2 |
| | — |
| | 0.2 |
| | — |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | 0.2 |
| | — |
| | 0.2 |
|
| Real estate | | — |
| | — |
| | — |
| | — |
| |
| Tangible assets | | 0.1 |
| | — |
| | 0.1 |
| | — |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
|
| Total Master trust assets | | 9.1 |
| | 0.3 |
| | 8.8 |
| | — |
| | 0.4 |
| | 7.7 |
| | — |
| | 8.1 |
| | 0.3 |
| | 8.8 |
| | — |
| | 9.1 |
|
| Derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Forward power contracts | | 10.8 |
| | — |
| | 10.8 |
| | — |
| |
| Interest rate hedge | | 1.8 |
| | — |
| | 1.8 |
| | — |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
|
| Natural gas | | 0.2 |
| | 0.2 |
| | — |
| | — |
| |
| Total Derivative assets | | 12.8 |
| | 0.2 |
| | 12.6 |
| | — |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 21.9 |
| | $ | 0.5 |
| | $ | 21.4 |
| | $ | — |
| | $ | 0.4 |
| | $ | 9.2 |
| | $ | — |
| | $ | 9.6 |
| | $ | 0.3 |
| | $ | 10.3 |
| | $ | — |
| | $ | 10.6 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| FTRs | | $ | 0.3 |
| | $ | — |
| | $ | — |
| | $ | 0.3 |
| |
| Natural gas | | 0.1 |
| | 0.1 |
| | — |
| | — |
| |
| Forward power contracts | | 14.9 |
| | — |
| | 14.9 |
| | — |
| |
| Total derivative liabilities | | 15.3 |
| | 0.1 |
| | 14.9 |
| | 0.3 |
| |
Long-term debt (b) | | 1,819.3 |
| | — |
| | 1,801.5 |
| | 17.8 |
| |
| Long-term debt | | | $ | — |
| | $ | 1,501.9 |
| | $ | 17.7 |
| | $ | 1,519.6 |
| | $ | — |
| | $ | 1,801.5 |
| | $ | 17.8 |
| | $ | 1,819.3 |
|
| | |
|
| | | | | | | | | | | | | |
|
| | | | | | | |
|
|
| Total liabilities | | $ | 1,834.6 |
| | $ | 0.1 |
| | $ | 1,816.4 |
| | $ | 18.1 |
| | $ | — |
| | $ | 1,501.9 |
| | $ | 17.7 |
| | $ | 1,519.6 |
| | $ | — |
| | $ | 1,801.5 |
| | $ | 17.8 |
| | $ | 1,819.3 |
|
| |
| (a) | Includes credit valuation adjustment |
| |
(b) | Amounts exclude immaterial capital lease obligations |
The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DPL was determined as follows:
|
| | | | | | | | | | | | | | | | |
| Assets and Liabilities at Fair Value |
| | | | | Level 1 | | Level 2 | | Level 3 |
| $ in millions | | Fair Value at December 31, 2016 (a) | | Based on
Quoted Prices in
Active Markets | | Other
observable
inputs | | Unobservable inputs |
| Assets | | | | | | | | |
| Master trust assets | | | | | | | | |
| Money market funds | | $ | 0.4 |
| | $ | 0.4 |
| | $ | — |
| | $ | — |
|
| Equity securities | | 3.4 |
| | — |
| | 3.4 |
| | — |
|
| Debt securities | | 4.4 |
| | — |
| | 4.4 |
| | — |
|
| Hedge funds | | 0.1 |
| | — |
| | 0.1 |
| | — |
|
| Real estate | | 0.3 |
| | — |
| | 0.3 |
| | — |
|
| Tangible assets | | 0.1 |
| | — |
| | 0.1 |
| | — |
|
| Total Master trust assets | | 8.7 |
| | 0.4 |
| | 8.3 |
| | — |
|
| Derivative assets | | | | | | | | |
| Forward power contracts | | 19.5 |
| | — |
| | 19.5 |
| | — |
|
| Interest rate hedges | | 1.2 |
| | — |
| | 1.2 |
| | — |
|
| FTRs | | 0.1 |
| | — |
| | — |
| | 0.1 |
|
| Total derivative assets | | 20.8 |
| | — |
| | 20.7 |
| | 0.1 |
|
| | | | | | | | | |
| Total assets | | $ | 29.5 |
| | $ | 0.4 |
| | $ | 29.0 |
| | $ | 0.1 |
|
| | | | | | | | | |
| Liabilities | | | | | | | | |
| Interest rate hedges | | $ | 0.7 |
| | $ | — |
| | $ | 0.7 |
| | $ | — |
|
| Forward power contracts | | 28.5 |
| | — |
| | 26.0 |
| | 2.5 |
|
| Total derivative liabilities | | 29.2 |
| | — |
| | 26.7 |
| | 2.5 |
|
Long-term debt (b) | | 1,907.7 |
| | — |
| | 1,889.7 |
| | 18.0 |
|
| Fair value per table above | | $ | 1,907.7 |
| | | | | | |
| | |
|
| | | | | | |
| Total liabilities | | $ | 1,936.9 |
| | $ | — |
| | $ | 1,916.4 |
| | $ | 20.5 |
|
| |
(a) | Includes credit valuation adjustment |
| |
(b) | Amounts exclude immaterial capital lease obligations |
Our financial instruments are valued using the market approach in the following categories:
Level 1 inputs are used for derivative contracts, such as heating oil futures, and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.
Level 2 inputs are used to value derivatives such as forward powerinterest rate hedge contracts (which are traded on the OTC market, but which are valued using prices on the NYMEX for similar contracts on the OTC market).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 financial transmission rights,certain debt balances are considered a Level 3 input because the monthly auctionsnotes are considered inactive.not publicly traded. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.long-term debt is fair valued for disclosure purposes only.
Approximately 98.7%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. AROs for asbestos, ash ponds, underground storage tanks, and river structures decreased due to changes in our estimates of costs to be incurred byIn 2018, DPL recorded a net amountreduction to its ARO liability for Conesville's ash pond and landfill of $2.6 million ($1.7 million after tax) in 2017 and increased by a net amount of $72.9 million ($47.4 million after tax) in 2016 largely driven by the increases to the AROs for the Stuart and Killen plants discussed below. Increases to the AROs for the Stuart and Killen plants totaling $67.9 million ($44.1 million after tax) were recorded in 2016 to reflect revised estimated closure expenditures as well as plant closure dates that are earlier than previously forecast. Smaller changes were also recordedrevisions to thecash flow and timing estimates. The balance of AROs for certain other plants to reflect changes in estimated closure costs.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 415 – Property, Plant and EquipmentDiscontinued Operations for moreadditional information about AROs.on AROs associated with our discontinued operations.
When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount.
The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Measurement | | Carrying | | Fair Value | | Gross |
| $ in millions | | Date | | Amount (c) | | Level 1 | | Level 2 | | Level 3 | | Loss |
Long-lived assets (a) | | | | | | | | | | | | |
| | | | | Year ended December 31, 2017 |
| AES Ohio Generation peakers | | December 31, 2017 | | $ | 346.9 |
| | $ | — |
| | $ | — |
| | $ | 237.5 |
| | $ | 109.4 |
|
| Stuart | | March 31, 2017 | | $ | 42.4 |
| | $ | — |
| | $ | — |
| | $ | 3.3 |
| | $ | 39.1 |
|
| Killen | | March 31, 2017 | | $ | 35.2 |
| | $ | — |
| | $ | — |
| | $ | 7.9 |
| | 27.3 |
|
| | | | | | | | | | | | | $ | 175.8 |
|
| | | | | | | | | | | | | |
| | | | | Year ended December 31, 2016 |
| Killen | | December 31, 2016 | | $ | 118.2 |
| | $ | — |
| | $ | — |
| | $ | 42.8 |
| | $ | 75.4 |
|
| Stuart | | December 31, 2016 | | $ | 285.9 |
| | $ | — |
| | $ | — |
| | $ | 57.4 |
| | 228.5 |
|
| Miami Fort | | December 31, 2016 | | $ | 185.9 |
| | $ | — |
| | $ | — |
| | $ | 36.5 |
| | 149.4 |
|
| Zimmer | | December 31, 2016 | | $ | 168.4 |
| | $ | — |
| | $ | — |
| | $ | 23.7 |
| | 144.7 |
|
| Conesville | | December 31, 2016 | | $ | 25.0 |
| | $ | — |
| | $ | — |
| | $ | 1.1 |
| | 23.9 |
|
| Hutchings peaking facilities | | December 31, 2016 | | $ | 3.2 |
| | $ | — |
| | $ | — |
| | $ | 1.6 |
| | 1.6 |
|
| Killen | | June 30, 2016 | | $ | 315.1 |
| | $ | — |
| | $ | — |
| | $ | 84.3 |
| | 230.8 |
|
| Certain peaking facilities | | June 30, 2016 | | $ | 9.9 |
| | $ | — |
| | $ | — |
| | $ | 5.2 |
| | 4.7 |
|
| | | | | | | | | | | | | $ | 859.0 |
|
| | | | | | | | | | | | | |
Goodwill (b) | | | | | | | | | | | | |
| | | | | Year ended December 31, 2015 |
DP&L reporting unit | | December 31, 2015 | | $ | 317.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 317.0 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Measurement | | Carrying | | Fair Value | | Gross |
| $ in millions | | Date | | Amount (b) | | Level 1 | | Level 2 | | Level 3 | | Loss |
Long-lived assets (a) | | | | | | | | | | | | |
| | | | | Year ended December 31, 2016 |
| Conesville | | December 31, 2016 | | $ | 25.0 |
| | $ | — |
| | $ | — |
| | $ | 1.1 |
| | 23.9 |
|
| |
| (a) | See Note 1517 – Fixed-asset Impairments for further information |
| |
| (b) | See Note 7 – Goodwill for further information |
| |
(c) | 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, 2017:
|
| | | | | | | | | | | | |
| $ in millions | | Measurement date | | Fair value | | Valuation technique | | Unobservable input | | Range (weighted average) |
| Long-lived assets held and used: |
| | | | | Year ended December 31, 2017 |
| AES Ohio Generation peakers | | December 31, 2017 | | $ | 237.5 |
| | Discounted cash flow | | Indicative offer price | | |
| | | | | | | | | | | |
| Stuart | | March 31, 2017 | | $ | 3.3 |
| | Discounted cash flow | | Pre-tax operating margin
(through remaining life) | | 10.0% |
| | | | | | | | | Weighted-average cost of capital | | 7.0% |
| | | | | | | | | | | |
| Killen | | March 31, 2017 | | $ | 7.9 |
| | Discounted cash flow | | Pre-tax operating margin
(through remaining life) | | 22.0% |
| | | | | | | | | Weighted-average cost of capital | | 7.0% |
The following summarizes the significant unobservable inputs used in the Level 3 measurement on a non-recurring basis during the year ended December 31, 2016:
|
| | | | | | | | | | | | |
| $ in millions | | Measurement date | | Fair value | | Valuation technique | | Unobservable input | | Range (weighted average) |
| Long-lived assets held and used: |
| | | | | Year ended December 31, 2016 |
| Killen | | December 31, 2016 | | $ | 42.8 |
| | Discounted cash flow | | Annual revenue growth | | -14.2% to 2.9% (-8.0%) |
| | | | | | | | | Annual pre-tax operating margin | | -56.6% to 42.4% (-15.5%) |
| | | | | | | | | Weighted-average cost of capital | | 10.0% |
| | | | | | | | | | | |
| Stuart | | December 31, 2016 | | $ | 57.4 |
| | Discounted cash flow | | Annual revenue growth | | -11.9% to 1.1% (-4.7%) |
| | | | | | | | | Annual pre-tax operating margin | | -61.4% to 75.1% (8.0%) |
| | | | | | | | | Weighted-average cost of capital | | 10.0% |
| | | | | | | | | | | |
| Miami Fort | | December 31, 2016 | | $ | 36.5 |
| | Market value | | Indicative offer price | | |
| | | | | | | | | | | |
| Zimmer | | December 31, 2016 | | $ | 23.7 |
| | Market value | | Indicative offer price | | |
| | | | | | | | | | | |
| Conesville | | December 31, 2016 | | $ | 1.1 |
| | Discounted cash flow | | Annual revenue growth | | -19.3% to 10.9% (0.6%) |
| | | | | | | | | Annual pre-tax operating margin | | -54.3% to 99.4% (20.2%) |
| | | | | | | | | Weighted-average cost of capital | | N/A |
| | | | | | | | | | | |
| Hutchings peaking facilities | | December 31, 2016 | | $ | 1.6 |
| | Discounted cash flow | | Annual revenue growth | | -19.5% to -25.9% (-0.7%) |
| | | | | | | | Annual pre-tax operating margin | | -40.3% to 63.1% (12.1%) |
| | | | | | | | | Weighted-average cost of capital | | 7.0% |
| | | | | | | | | | | |
| Killen | | June 30, 2016 | | $ | 84.3 |
| | Discounted cash flow | | Annual revenue growth | | -11.0% to 13.0% (2.0%) |
| | | | | | | | | Annual pre-tax operating margin | | -50.0% to 67.0% (6.0%) |
| | | | | | | | | Weighted-average cost of capital | | 11.0% |
| | | | | | | | | | | |
| Certain peaking facilities | | June 30, 2016 | | $ | 5.2 |
| | Discounted cash flow | | Annual revenue growth | | -22.0% to 17.0% (-3.0%) |
| | | | | | | | | Annual pre-tax operating margin | | -29.0% to 24.0% (-4.0%) |
| | | | | | | | | Weighted-average cost of capital | | 7.0% |
|
| | | | | | | | | | | | |
| $ in millions | | Measurement date | | Fair value | | Valuation technique | | Unobservable input | | Range (weighted average) |
| Long-lived assets held and used: |
| | | | | Year ended December 31, 2016 |
| Conesville | | December 31, 2016 | | $ | 1.1 |
| | Discounted cash flow | | Annual revenue growth | | -19.3% to 10.9% (0.6%) |
| | | | | | | | | Annual pre-tax operating margin | | -54.3% to 99.4% (20.2%) |
| | | | | | | | | Weighted-average cost of capital | | N/A |
Note 6 – Derivative Instruments and Hedging Activities
In the normal course of business, DPL enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually
assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes.
At December 31, 2017,2018, DPL's outstanding derivative instruments were as follows:
|
| | | | | | | | | | | | | | | | |
| Commodity | | Accounting Treatment (a) | | Unit | | Purchases
(in thousands) | | Sales
(in thousands) | | Net Purchases/ (Sales)
(in thousands) |
| FTRs | | Not designated | | MWh | | 2.1 |
| | — |
| | 2.1 |
|
| Natural Gas | | Not designated | | Dths | | 3,322.5 |
| | (390.0 | ) | | 2,932.5 |
|
| Forward Power Contracts | | Designated | | MWh | | 678.5 |
| | (1,667.0 | ) | | (988.5 | ) |
| Forward Power Contracts | | Not designated | | MWh | | 871.0 |
| | (765.6 | ) | | 105.4 |
|
| Interest Rate Swaps | | Designated | | USD | | $ | 200,000.0 |
| | $ | — |
| | $ | 200,000.0 |
|
|
| | | | | | | | | | | | | | | | |
| 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, 2016,2017, DPL's outstanding derivative instruments were as follows:
| | | Commodity | | Accounting Treatment (a) | | Unit | | Purchases
(in thousands) | | Sales
(in thousands) | | Net Purchases/ (Sales)
(in thousands) | | Accounting Treatment (a) | | Unit | | Purchases
(in thousands) | | Sales
(in thousands) | | Net Purchases/ (Sales)
(in thousands) |
FTRs | | Not designated | | MWh | | 2.3 |
| | — |
| | 2.3 |
| | Not designated | | MWh | | 2.1 |
| | — |
| | 2.1 |
|
Natural Gas | | Not designated | | Dths | | 1,590.0 |
| | — |
| | 1,590.0 |
| | Not designated | | Dths | | 3,322.5 |
| | (390.0 | ) | | 2,932.5 |
|
Forward Power Contracts | | Designated | | MWh | | 342.9 |
| | (9,974.5 | ) | | (9,631.6 | ) | | Designated | | MWh | | 678.5 |
| | (1,667.0 | ) | | (988.5 | ) |
Forward Power Contracts | | Not designated | | MWh | | 2,568.3 |
| | (2,020.9 | ) | | 547.4 |
| | Not designated | | MWh | | 871.0 |
| | (765.6 | ) | | 105.4 |
|
| Interest Rate Swaps | | Designated | | USD | | $ | 200,000.0 |
| | $ | — |
| | $ | 200,000.0 |
| | 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 hedgesFlow 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 enterIn 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 $200.0$140.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0$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:
| | | | | Years ended December 31, | | Years ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| $ in millions (net of tax) | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges |
| Beginning accumulated derivative gain / (loss) in AOCI | | $ | (4.3 | ) | | $ | 17.4 |
| | $ | 9.2 |
| | $ | 17.5 |
| | $ | 0.2 |
| | $ | 18.3 |
| | $ | (2.8 | ) | | $ | 17.5 |
| | $ | (4.3 | ) | | $ | 17.4 |
| | $ | 9.2 |
| | $ | 17.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net gains / (losses) associated with current period hedging transactions | | 8.8 |
| | 0.8 |
| | 15.7 |
| | 0.4 |
| | 18.2 |
| | — |
| | — |
| | (0.1 | ) | | 8.8 |
| | 0.8 |
| | 15.7 |
| | 0.4 |
|
| Net gains / (losses) reclassified to earnings: | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest Expense | | — |
| | (0.7 | ) | | — |
| | (0.5 | ) | | — |
| | (0.8 | ) | | — |
| | (0.8 | ) | | — |
| | (0.7 | ) | | — |
| | (0.5 | ) |
| Revenues | | (9.8 | ) | | — |
| | (35.6 | ) | | — |
| | (12.0 | ) | | — |
| |
| Purchased Power | | 2.5 |
| | — |
| | 6.4 |
| | — |
| | 2.8 |
| | — |
| |
| Income / (loss) from discontinued operations before income tax | | | 3.2 |
| | — |
| | (7.3 | ) | | — |
| | (29.2 | ) | | — |
|
| Ending accumulated derivative gain / (loss) in AOCI | | $ | (2.8 | ) | | $ | 17.5 |
| | $ | (4.3 | ) | | $ | 17.4 |
| | $ | 9.2 |
| | $ | 17.5 |
| | $ | 0.4 |
| | $ | 16.6 |
| | $ | (2.8 | ) | | $ | 17.5 |
| | $ | (4.3 | ) | | $ | 17.4 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
Portion expected to be reclassified to earnings in the next twelve months (a) | | $ | (2.7 | ) | | $ | (0.7 | ) | | | | | | | | | | $ | — |
| | $ | (0.8 | ) | | | | | | | | |
| | | | | | | | | | | | | | |
| Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | | 3 |
| | 32 |
| | | | | | | | | | 0 |
| | 20 |
| | | | | | | | |
| |
| (a) | The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes. |
Net gains or losses associated with the ineffective portion of the hedging transactions were immaterial in the periods presented.
Derivatives not designatedNot Designated as hedgesHedges
CertainIn prior years certain derivative contracts arewere entered into on a regular basis as part of our risk management program but dodid not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts arewere 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 enterentered into as part of our risk management program may behave been settled financially, by physical delivery or net settled with the counterparty. We markmarked 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 have beenwe 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 2016 and 2015:2016:
| | | | | Year ended December 31, 2017 | | Year ended December 31, 2018 |
| $ in millions | | FTRs | | Power | | Natural Gas | | Total | | FTRs | | Power | | Natural Gas | | Total |
| Change in unrealized gain / (loss) | | $ | (0.4 | ) | | $ | 1.9 |
| | $ | 0.1 |
| | $ | 1.6 |
| | $ | 0.3 |
| | $ | — |
| | $ | (0.1 | ) | | $ | 0.2 |
|
| Realized gain / (loss) | | 0.8 |
| | (0.7 | ) | | 1.5 |
| | 1.6 |
| | 0.4 |
| | — |
| | 0.3 |
| | 0.7 |
|
| Total | | $ | 0.4 |
| | $ | 1.2 |
| | $ | 1.6 |
| | $ | 3.2 |
| | $ | 0.7 |
| | $ | — |
| | $ | 0.2 |
| | $ | 0.9 |
|
| | |
| |
| |
| |
| |
| |
| |
| |
|
| Recorded on Balance Sheet: | | | | | | | | | |
| Regulatory asset | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Recorded in Statement of Operations: gain / (loss) | | Revenue | | — |
| | (1.2 | ) | | — |
| | (1.2 | ) | |
| Purchased Power | | 0.4 |
| | 2.4 |
| | 1.6 |
| | 4.4 |
| |
| Income / (loss) from discontinued operations before income tax | | | $ | 0.7 |
| | $ | — |
| | $ | 0.2 |
| | $ | 0.9 |
|
| Total | | $ | 0.4 |
| | $ | 1.2 |
| | $ | 1.6 |
| | $ | 3.2 |
| | $ | 0.7 |
| | $ | — |
| | $ | 0.2 |
| | $ | 0.9 |
|
| | | | | Year ended December 31, 2016 | | Year ended December 31, 2017 |
| $ in millions | | FTRs | | Power | | Natural Gas | | Total | | FTRs | | Power | | Natural Gas | | Total |
| Change in unrealized gain / (loss) | | $ | 0.3 |
| | $ | 4.0 |
| | $ | — |
| | $ | 4.3 |
| | $ | (0.4 | ) | | $ | 1.9 |
| | $ | 0.1 |
| | $ | 1.6 |
|
| Realized gain / (loss) | | (0.6 | ) | | (7.2 | ) | | 2.6 |
| | (5.2 | ) | | 0.8 |
| | (0.7 | ) | | 1.5 |
| | 1.6 |
|
| Total | | $ | (0.3 | ) | | $ | (3.2 | ) | | $ | 2.6 |
| | $ | (0.9 | ) | | $ | 0.4 |
| | $ | 1.2 |
| | $ | 1.6 |
| | $ | 3.2 |
|
| | |
| |
| |
| |
| |
| |
| |
| |
|
| Recorded on Balance Sheet: | |
| Regulatory asset | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Recorded in Statement of Operations: gain / (loss) | | Revenue | | $ | — |
| | $ | (17.3 | ) | | $ | — |
| | $ | (17.3 | ) | |
| Purchased Power | | (0.3 | ) | | 14.1 |
| | 2.6 |
| | 16.4 |
| |
| Income / (loss) from discontinued operations before income tax | | | $ | 0.4 |
| | $ | 1.2 |
| | $ | 1.6 |
| | $ | 3.2 |
|
| Total | | $ | (0.3 | ) | | $ | (3.2 | ) | | $ | 2.6 |
| | $ | (0.9 | ) | | $ | 0.4 |
| | $ | 1.2 |
| | $ | 1.6 |
| | $ | 3.2 |
|
| | | | | Year ended December 31, 2015 | | Year ended December 31, 2016 |
| $ in millions | | Heating Oil | | FTRs | | Power | | Natural Gas | | Total | | FTRs | | Power | | Natural Gas | | Total |
| Change in unrealized gain / (loss) | | $ | 0.4 |
| | $ | 0.3 |
| | $ | (6.4 | ) | | $ | 0.1 |
| | $ | (5.6 | ) | | $ | 0.3 |
| | $ | 4.0 |
| | $ | — |
| | $ | 4.3 |
|
| Realized gain / (loss) | | (0.3 | ) | | (0.2 | ) | | (9.8 | ) | | (0.1 | ) | | (10.4 | ) | | (0.6 | ) | | (7.2 | ) | | 2.6 |
| | (5.2 | ) |
| Total | | $ | 0.1 |
| | $ | 0.1 |
| | $ | (16.2 | ) | | $ | — |
| | $ | (16.0 | ) | | $ | (0.3 | ) | | $ | (3.2 | ) | | $ | 2.6 |
| | $ | (0.9 | ) |
| | |
| |
| |
| |
| |
| |
| |
| |
| |
|
| Recorded on Balance Sheet | |
| Regulatory asset | | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
| |
Recorded in Statement of Operations: gain / (loss) | | Fuel | | — |
| | — |
| | 27.4 |
| | — |
| | 27.4 |
| |
| Purchased Power | | — |
| | 0.1 |
| | (43.6 | ) | | — |
| | (43.5 | ) | |
| Income / (loss) from discontinued operations before income tax | | | $ | (0.3 | ) | | $ | (3.2 | ) | | $ | 2.6 |
| | $ | (0.9 | ) |
| Total | | $ | 0.1 |
| | $ | 0.1 |
| | $ | (16.2 | ) | | $ | — |
| | $ | (16.0 | ) | | $ | (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.
|
| | | | | | | | | | | | | | | | | | |
| Fair Values of Derivative Instruments |
| December 31, 2017 |
| | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheets | | |
| $ in millions | | Hedging Designation | | Gross Fair Value as presented in the Consolidated Balance Sheets (a) | | Financial Instruments with Same Counterparty in Offsetting Position | | Cash Collateral | | Net Amount |
| Assets | | | | | | | | | | |
| Short-term derivative positions (presented in Other current assets) | | | | | | |
| Forward power contracts | | Designated | | $ | 4.9 |
| | $ | (4.9 | ) | | $ | — |
| | $ | — |
|
| Forward power contracts | | Not designated | | 5.3 |
| | (3.7 | ) | | — |
| | 1.6 |
|
| Natural gas | | Not designated | | 0.2 |
| | (0.1 | ) | | — |
| | 0.1 |
|
| | | | | | | | | | | |
| Long-term derivative positions (presented in Other deferred assets) | | |
| | |
| | |
|
| Interest Rate Swaps | | Designated | | 1.8 |
| | — |
| | — |
| | 1.8 |
|
| Forward power contracts | | Designated | | — |
| | — |
| | — |
| | — |
|
| Forward power contracts | | Not designated | | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Total assets | | | | $ | 12.8 |
| | $ | (8.7 | ) | | $ | — |
| | $ | 4.1 |
|
| | | | | | | | | | | |
| Liabilities | | | | | | | | | | |
| Short-term derivative positions (presented in Other current liabilities) | | | | |
| Forward power contracts | | Designated | | $ | 9.0 |
| | $ | (4.9 | ) | | $ | (1.4 | ) | | $ | 2.7 |
|
| Forward power contracts | | Not designated | | 5.9 |
| | (3.7 | ) | | — |
| | 2.2 |
|
| Natural gas | | Not designated | | 0.1 |
| | (0.1 | ) | | — |
| | — |
|
| FTRs | | Not designated | | 0.3 |
| | — |
| | — |
| | 0.3 |
|
| Total liabilities | | | | $ | 15.3 |
| | $ | (8.7 | ) | | $ | (1.4 | ) | | $ | 5.2 |
|
|
| | | | | | | | | | | | | | | | | | |
| Fair Values of Derivative Instruments |
| December 31, 2018 |
| | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheets | | |
| $ in millions | | Hedging Designation | | Gross Fair Value as presented in the Consolidated Balance Sheets (a) | | Financial Instruments with Same Counterparty in Offsetting Position | | Cash Collateral | | Net Amount |
| Assets | | | | | | | | | | |
| Short-term derivative positions (presented in Other prepayments and current assets) | | | | |
| Interest Rate Swaps | | Designated | | $ | 0.9 |
| | $ | — |
| | $ | — |
| | $ | 0.9 |
|
| | | | | | | | | | | |
| Long-term derivative positions (presented in Other deferred assets) | | | | | | |
| Interest Rate Swaps | | Designated | | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Total assets | | | | $ | 1.5 |
| | $ | — |
| | $ | — |
| | $ | 1.5 |
|
| | | | | | | | | | | |
| |
| (a) | Includes credit valuation adjustment. |
|
| | | | | | | | | | | | | | | | | | |
| Fair Values of Derivative Instruments |
| December 31, 2017 |
| | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheets | | |
| $ in millions | | Hedging Designation | | Gross Fair Value as presented in the Consolidated Balance Sheets (a) | | Financial Instruments with Same Counterparty in Offsetting Position | | Cash Collateral | | Net Amount |
| Assets | | | | | | | | | | |
| Short-term derivative positions (presented in Current assets of discontinued operations and held-for-sale businesses) | | | | | | |
| Forward power contracts | | Designated | | $ | 4.9 |
| | $ | (4.9 | ) | | $ | — |
| | $ | — |
|
| Forward power contracts | | Not designated | | 5.3 |
| | (3.7 | ) | | — |
| | 1.6 |
|
| FTRs | | Not designated | | 0.2 |
| | (0.1 | ) | | — |
| | 0.1 |
|
| | | | | | | | | | | |
| Long-term derivative positions (presented in Other deferred assets) | | | | | | |
| Interest rate swaps | | Designated | | 1.5 |
| | — |
| | — |
| | 1.5 |
|
| | | | | | | | | | | |
| Long-term derivative positions (presented in Non-current assets of discontinued operations and held-for-sale businesses) | | | | | | |
| Forward power contracts | | Not designated | | 0.6 |
| | — |
| | — |
| | 0.6 |
|
| Total assets | | | | $ | 12.5 |
| | $ | (8.7 | ) | | $ | — |
| | $ | 3.8 |
|
| | | | | | | | | | | |
| Liabilities | | | | | | | | | | |
| Short-term derivative positions (presented in Current liabilities of discontinued operations and held-for-sale businesses) | | | | | | |
| Forward power contracts | | Designated | | $ | 9.0 |
| | $ | (4.9 | ) | | $ | (1.4 | ) | | 2.7 |
|
| Forward power contracts | | Not designated | | 5.9 |
| | (3.7 | ) | | — |
| | 2.2 |
|
| Natural gas | | Not designated | | 0.1 |
| | (0.1 | ) | | — |
| | — |
|
| FTRs | | Not designated | | 0.3 |
| | — |
| | — |
| | 0.3 |
|
| Total liabilities | | | | $ | 15.3 |
| | $ | (8.7 | ) | | $ | (1.4 | ) | | $ | 5.2 |
|
| |
| (a) | Includes credit valuation adjustment. |
|
| | | | | | | | | | | | | | | | | | |
| Fair Values of Derivative Instruments |
| December 31, 2016 |
| | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheets | | |
| $ in millions | | Hedging Designation | | Gross Fair Value as presented in the Consolidated Balance Sheets (a) | | Financial Instruments with Same Counterparty in Offsetting Position | | Cash Collateral | | Net Amount |
| Assets | | | | | | | | | | |
| Short-term derivative positions (presented in Other current assets) | | | | | | |
| Forward power contracts | | Designated | | $ | 11.0 |
| | $ | (10.5 | ) | | $ | — |
| | $ | 0.5 |
|
| Forward power contracts | | Not designated | | 6.0 |
| | (4.7 | ) | | — |
| | 1.3 |
|
| FTRs | | Not designated | | 0.1 |
| | — |
| | — |
| | 0.1 |
|
| | | | | | | | | | | |
| Long-term derivative positions (presented in Other deferred assets) | | | | | | |
| Interest rate swaps | | Designated | | 1.2 |
| | — |
| | — |
| | 1.2 |
|
| Forward power contracts | | Designated | | 0.6 |
| | (0.6 | ) | | — |
| | — |
|
| Forward power contracts | | Not designated | | 1.9 |
| | (1.0 | ) | | — |
| | 0.9 |
|
| Total assets | | | | $ | 20.8 |
| | $ | (16.8 | ) | | $ | — |
| | $ | 4.0 |
|
| | | | | | | | | | | |
| Liabilities | | | | | | | | | | |
| Short-term derivative positions (presented in Other current liabilities) | | | | | | |
| Interest rate swaps | | Designated | | $ | 0.7 |
| | $ | — |
| | $ | — |
| | $ | 0.7 |
|
| Forward power contracts | | Designated | | 16.4 |
| | (10.5 | ) | | (5.5 | ) | | 0.4 |
|
| Forward power contracts | | Not designated | | 7.7 |
| | (4.7 | ) | | — |
| | 3.0 |
|
| | | | | | | | | | | |
| Long-term derivative positions (presented in Other deferred liabilities) | | | | | | |
| Forward power contracts | | Designated | | 2.4 |
| | (0.6 | ) | | (0.8 | ) | | 1.0 |
|
| Forward power contracts | | Not designated | | 2.0 |
| | (1.0 | ) | | — |
| | 1.0 |
|
| Total liabilities | | | | $ | 29.2 |
| | $ | (16.8 | ) | | $ | (6.3 | ) | | $ | 6.1 |
|
| |
(a) | Includes credit valuation adjustment. |
Credit risk-related contingent features
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require us to post collateral if our credit ratings drop below certain thresholds. We have crossed this threshold and our counterparties could request that we post collateral for our net liability position with them. As of the date of the filing of this report, we have not had to post collateral with any of these counterparties.
The aggregate fair value of DPL’s derivative instruments that were in a MTM loss position at December 31, 2017 is $15.3 million. This amount is offset by $8.7 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $1.4 million. Since our debt is below investment grade, we could have to post collateral for the remaining $4.9 million.
Note 7 – Goodwill
DP&L Reporting Unit
During the fourth quarter of 2015, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $317.0 million. The reporting unit failed Step 1 as its fair value was less than its carrying amount, which was primarily due to a decrease forecasted in dark spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from the CP product. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were forward
commodity price curves, expected revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to have no implied fair value after the hypothetical purchase price allocation under the accounting guidance for business combinations; therefore, a full impairment of the remaining goodwill balance of $317.0 million was recognized.
The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no cash or financial statement tax benefit related to the impairment.
Note 8 – DebtLong-term debt
| | | Long-term debt | | | | | | | | |
| $ in millions | | Interest Rate | | Maturity | | December 31, 2017 | | December 31, 2016 | | Interest Rate | | Maturity | | December 31, 2018 | | December 31, 2017 |
| Term loan - rates from: 4.01% - 4.60% (a) and 4.00% - 4.01% (b) | | 2022 | | $ | 440.6 |
| | $ | 445.0 |
| |
| Tax-exempt First Mortgage Bonds | | 4.8% | | 2036 | | — |
| | 100.0 |
| |
| Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | | 2020 | | 200.0 |
| | 200.0 |
| |
| Term loan - rates from: 3.57% - 4.82% (a) and 4.00% - 4.60% (b) | | | 2022 | | $ | 436.1 |
| | $ | 440.6 |
|
| Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | | | 2020 | | 140.0 |
| | 200.0 |
|
| U.S. Government note | | 4.2% | | 2061 | | 17.8 |
| | 18.0 |
| | 4.2% | | 2061 | | 17.7 |
| | 17.8 |
|
| Capital leases | |
| |
| | 0.2 |
| | 0.4 |
| |
| Unamortized deferred financing costs | | (9.8 | ) | | (10.7 | ) | | (6.3 | ) | | (9.8 | ) |
| Unamortized debt discounts and premiums, net | | (2.0 | ) | | (5.5 | ) | | (1.4 | ) | | (2.0 | ) |
| Total long-term debt at subsidiary | | 646.8 |
| | 747.2 |
| | 586.1 |
| | 646.6 |
|
| | | | | | | | | |
| Bank term loan - rates from: 3.02% - 4.10% (a) and 2.67% - 3.02% (b) | | 2020 | | 70.0 |
| | 125.0 |
| | 2020 | | — |
| | 70.0 |
|
| Senior unsecured bonds | | 6.75% | | 2019 | | 200.0 |
| | 200.0 |
| | 6.75% | | 2019 | | 99.0 |
| | 200.0 |
|
| Senior unsecured bonds | | 7.25% | | 2021 | | 780.0 |
| | 780.0 |
| | 7.25% | | 2021 | | 780.0 |
| | 780.0 |
|
| Note to DPL Capital Trust II (c) | | 8.125% | | 2031 | | 15.6 |
| | 15.6 |
| | 8.125% | | 2031 | | 15.6 |
| | 15.6 |
|
| Unamortized deferred financing costs | | (6.8 | ) | | (8.8 | ) | | (4.3 | ) | | (6.8 | ) |
| Unamortized debt discounts and premiums, net | | (0.5 | ) | | (0.6 | ) | | (0.5 | ) | | (0.6 | ) |
| Total long-term debt | | 1,705.1 |
| | 1,858.4 |
| | 1,475.9 |
| | 1,704.8 |
|
| Less: current portion | | (4.7 | ) | | (29.7 | ) | | (103.6 | ) | | (4.6 | ) |
| Long-term debt, net of current portion | | $ | 1,700.4 |
| | $ | 1,828.7 |
| | $ | 1,372.3 |
| | $ | 1,700.2 |
|
| |
| (a) | Range of interest rates for the year ended December 31, 2017.2018. |
| |
| (b) | Range of interest rates for the year ended December 31, 2016.2017. |
| |
| (c) | Note payable to related party. See Note 1312 – Related Party Transactions for additional information. |
At December 31, 2017,2018, maturities of long-term debt are summarized as follows:
| | | Due during the years ending December 31, | | |
| $ in millions | | |
| 2018 | $ | 4.7 |
| |
| 2019 | 224.5 |
| $ | 103.6 |
|
| 2020 | 254.6 |
| 144.7 |
|
| 2021 | 784.6 |
| 784.7 |
|
| 2022 | 422.9 |
| 422.8 |
|
| 2023 | | 0.2 |
|
| Thereafter | 32.7 |
| 32.4 |
|
| | 1,724.0 |
| 1,488.4 |
|
| Unamortized discounts and premiums, net | (2.5 | ) | (1.9 | ) |
| Deferred financing costs, net | | (10.6 | ) |
| Total long-term debt | $ | 1,721.5 |
| $ | 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.
Significant transactionsOn 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.
On December 15, 2017, shortly after DPL and AES Ohio Generation entered into an Asset Purchase Agreement agreeing There were no such transactions prior to sell Peaker assets to Kimura Power, DPL and its lenders amended DPL's revolving credit loan and term loan credit agreement. This agreement was amended to, among other things, (a) explicitly carve out the sale of DPL's Peaker assets and coal generation facilities from its "limitation on asset disposition" covenant, (b) modify the definition of Consolidated EBITDA (which is used for measuring the Consolidated Debt to EBITDA ratio and the Interest Coverage Ratio in the agreement), to also exclude, out-of-pocket third party costs and expenses incurred directly in connection with the implementation, negotiation, documentation and closing of the Generation Separation and up to $25.0 million of non-recurring cash expenses related to the closure, or sale, of generation stations, (c) modify the definition of "maturity date" used in the agreement to mean July 31, 2020; provided, however, if DPL fails to retire, redeem, or refinance at least $100.0 million in aggregate of principal amount of its senior unsecured bonds due October 1, 2019, then the maturity date shall be July, 1 2019, and (d) modify the maximum Consolidated Debt to EBITDA ratio permitted not to exceed 7.25 to 1.00 September 20, 2015 through December 31, 2018, 7.00 to 1.00 January 1, 2019 through June 30, 2019, 6.75 to 1.00 July 1, 2019 through December 31, 2019, and 6.50 to 1.00 January 1, 2020 and beyond. As part of this agreement DPL has also agreed to repay the remaining balance on its secured term loan within 10 days after receiving proceeds from the sale of the Peaker assets. This agreement was effective December 15, 2017, however certain provisions, including the modification of the Consolidated Debt to EBITDA covenant and the carving out of the sale of Peaker assets from its "limitation on asset disposition" covenant, are conditioned on the repayment in full of the term loan.
On December 8, 2017, DPL made a $30.0 million prepayment on its term loan. As of December 31, 2017, the outstanding balance was $70.0 million.
On May 26, 2017, DP&L commenced a tender offer to purchase any and all of the outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstanding bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plus accrued and unpaid interest) $21.9 million of these bonds. This call was completed on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of September 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of bonds was completed on October 30, 2017.
On January 6, 2016, DPL issued a Notice of Partial Redemption to the Trustee (Wells Fargo Bank N.A.) on the DPL 6.5% Senior Notes due 2016 (a component of the Dolphin Subsidiary II, Inc. debt). DPL notified the trustee that it was calling $73.0 million of the $130.0 million outstanding principal amount of these notes. The record date of this redemption was January 21, 2016, and the redemption date was February 5, 2016. These bonds were redeemed at par plus accrued interest and a make-whole premium of $2.4 million. On October 17, 2016, the remaining $57.0 million of outstanding principal was redeemed at par on their maturity date with cash on hand.
On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.
3, 2018.
Debt covenantsCovenants 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, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L) have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.
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.
DP&L doesnot have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL. DPL’s secured revolving credit agreement secured term loan, and senior unsecured notes due 2019 restrictalso 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 onetwo of the three major credit rating agencies is at least investment grade. As of December 31, 2017,2018, DPL’sDPL's leverage ratiosenior-long term debt rating was at 1.50 to 1.00 and DPL’s senior long-term debt rating from allleast investment grade by two of the three major credit rating agencies was below investment grade. As a result, as of December 31, 2017, DPL was prohibited under each of these agreements from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).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 93 – Income TaxesRegulatory 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’sunsecured revolving credit facilityagreement and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuancesale of the $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents)2015) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’sThe first measures Total Debt to Total Capitalization mayand 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 at any time; and, on and after1.00; except that, the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, which occurred October 1, 2017, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time. Except that after separation required compliance with this financial covenantratio shall be suspended (a)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&Lmaintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms As of the revolving credit facility or (b)December 31, 2018, DP&L's ratings meet those requirements and this ratio is suspended for the time period January 1, 2017 toquarter ended December 31, 2017 (as modified by the amendment described below) if DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt.2018.
On February 21, 2017, The second financial covenant measures EBITDA to Interest Expense. The TotalDP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modifiedConsolidated EBITDA to Consolidated Interest Charges ratio is calculated, at the definitionend of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter, ending December 31, 2016 and thereafter. With this amendment, DP&L was able to ensure compliance withby dividing consolidated EBITDA for theTotal Debt to Total Capitalization four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement, (before any amendment), the required Total Debtis to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75be not less than 2.50 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total DebtThis covenant was met with a ratio of 8.09 to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00. After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this2018.
time period previously was January 1, 2017DP&L doesnot have any meaningful restrictions in its debt financing documents prohibiting dividends to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets fromits parent, DP&L DPL.(or from October 1, 2017 through September 30, 2018). Generation Separation occurred on October 1, 2017.
As of December 31, 2017,2018, 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.
Note 98 – Income Taxes
DPL’s components of income tax expense on continuing operations were as follows:
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Computation of tax expense / (benefit) | | | | | | | | | | | | |
| Federal income tax benefit (a) | | $ | (42.0 | ) | | $ | (277.6 | ) | | $ | (81.0 | ) | |
| 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 | | (0.5 | ) | | (1.0 | ) | | (0.1 | ) | | 0.1 |
| | 0.1 |
| | — |
|
| Depreciation of AFUDC - Equity | | 0.8 |
| | 2.7 |
| | (3.5 | ) | |
| Depreciation of flow-through differences | | | (4.6 | ) | | 1.1 |
| | 3.3 |
|
| Investment tax credit amortized | | (0.3 | ) | | (0.4 | ) | | (0.5 | ) | | (0.3 | ) | | (0.3 | ) | | (0.4 | ) |
| Section 199 - domestic production deduction | | — |
| | (4.5 | ) | | (4.1 | ) | |
| Non-deductible goodwill impairment | | — |
| | — |
| | 111.0 |
| |
| Deferred tax adjustments | | | — |
| | (0.7 | ) | | (9.3 | ) |
| Accrual (settlement) for open tax years | | (0.4 | ) | | 2.2 |
| | — |
| | — |
| | (0.4 | ) | | 2.0 |
|
Other, net (b) | | 17.1 |
| | (0.2 | ) | | (1.8 | ) | | (1.2 | ) | | (2.5 | ) | | (2.3 | ) |
| Tax expense / (benefit) | | $ | (25.3 | ) | | $ | (278.8 | ) | | $ | 20.0 |
| | $ | 0.7 |
| | $ | (5.0 | ) | | $ | (2.4 | ) |
| |
| |
| |
| |
| |
| |
|
| Components of tax expense / (benefit) | | | | | | | | | | | | |
| Federal - current | | $ | (2.9 | ) | | $ | 14.7 |
| | $ | 30.1 |
| | $ | (17.9 | ) | | $ | 23.8 |
| | $ | (3.3 | ) |
| State and Local - current | | — |
| | 0.6 |
| | 0.8 |
| | 0.5 |
| | 0.2 |
| | — |
|
| Total current | | (2.9 | ) | | 15.3 |
| | 30.9 |
| | (17.4 | ) | | 24.0 |
| | (3.3 | ) |
| | | | | | | | | | | | | |
| Federal - deferred | | (22.0 | ) | | (290.2 | ) | | (9.9 | ) | | 18.3 |
| | (28.8 | ) | | 0.8 |
|
| State and local - deferred | | (0.4 | ) | | (3.9 | ) | | (1.0 | ) | | (0.2 | ) | | (0.2 | ) | | 0.1 |
|
| Total deferred | | (22.4 | ) | | (294.1 | ) | | (10.9 | ) | | 18.1 |
| | (29.0 | ) | | 0.9 |
|
| Tax expense / (benefit) | | $ | (25.3 | ) | | $ | (278.8 | ) | | $ | 20.0 |
| | $ | 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 $(0.3) million and $0.2$(0.9) million in the years ended December 31, 2017 2016, and 2015,2016, respectively, of income tax related to adjustments from prior years. The 2018 and 2017 tax yearyears also includesinclude a one-time remeasurement of deferred tax expense related to the recent enactment of the TCJA of $13.7 million.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, 20172018, 20162017 and 20152016:
| | | | | Years ended December 31, | | Years ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Statutory Federal tax rate | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 21.0 | % | | 35.0 | % | | 35.0 | % |
| State taxes, net of Federal tax benefit | | 0.4 | % | | 0.1 | % | | 0.1 | % | | 0.4 | % | | (1.5 | )% | | 0.2 | % |
| AFUDC - Equity | | (0.7 | )% | | (0.3 | )% | | 1.5 | % | |
| AFUDC - equity | | | (0.1 | )% | | 4.9 | % | | (5.0 | )% |
| Depreciation of flow-through differences | | | (14.6 | )% | | (17.6 | )% | | 26.7 | % |
| Amortization of investment tax credits | | 0.3 | % | | — | % | | 0.2 | % | | (1.0 | )% | | 5.1 | % | | (3.3 | )% |
| Section 199 - domestic production deduction | | — | % | | 0.6 | % | | 1.8 | % | |
| Non-deductible goodwill impairment | | — | % | | — | % | | (48.0 | )% | |
Other, net (a) | | (13.9 | )% | | (0.3 | )% | | 0.8 | % | |
| Deferred tax adjustments | | | — | % | | 11.0 | % | | (75.1 | )% |
| Permanent differences | | | — | % | | 4.8 | % | | 2.8 | % |
| Other, net | | | (3.5 | )% | | 35.2 | % | | (0.7 | )% |
| Effective tax rate | | 21.1 | % | | 35.1 | % | | (8.6 | )% | | 2.2 | % | | 76.9 | % | | (19.4 | )% |
| |
(a) | In 2017, this is primarily a result of the application of the TCJA. |
Deferred Income Taxes
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
| | Components of Deferred Tax Assets and Liabilities | | | | December 31, | | December 31, |
| $ in millions | | 2017 | | 2016 | | 2018 | | 2017 |
| Net non-current assets / (liabilities) | | | | | | | | |
| Depreciation / property basis | | $ | (103.6 | ) | | $ | (234.8 | ) | | $ | (112.0 | ) | | $ | (113.4 | ) |
| Income taxes recoverable / (payable) | | 11.0 |
| | (11.9 | ) | |
| Income taxes recoverable | | | 25.0 |
| | 11.0 |
|
| Regulatory assets | | (23.1 | ) | | (7.8 | ) | | (15.4 | ) | | (23.1 | ) |
| Investment tax credit | | 0.5 |
| | 0.5 |
| | 0.5 |
| | 0.7 |
|
| Compensation and employee benefits | | 11.3 |
| | 5.5 |
| | 1.4 |
| | 19.0 |
|
| Intangibles | | (0.4 | ) | | (1.5 | ) | | (0.3 | ) | | (0.4 | ) |
| Long-term debt | | (0.2 | ) | | (0.7 | ) | | (2.1 | ) | | (0.2 | ) |
Other (a) | | (6.7 | ) | | (1.7 | ) | | (13.2 | ) | | (7.1 | ) |
| Net non-current liabilities | | $ | (111.2 | ) | | $ | (252.4 | ) | | $ | (116.1 | ) | | $ | (113.5 | ) |
| |
| (a) | The Other caption includes deferred tax assets of $36.3$10.9 million in 20172018 and $38.3$9.3 million in 20162017 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $36.3$10.9 million in 20172018 and $38.3$9.3 million in 2016.2017. These net operating loss carryforwards expire from 20182019 to 2037. |
U. SU.S. Tax Reform
On December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law.
WeIn 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 reflectreflected the income tax effects of U.S. tax reform for which the accounting iswas complete and provisional amounts for those impacts for which the accounting under FASC 740 iswas incomplete, but a reasonable estimate could be determined.
We have calculatedcompleted our best estimatecalculation of the impact of the TCJA in our income tax provision for the year ended December 31, 20172018 in accordance with our understanding of the TCJA and guidance available as of the date of this filing, and as a result recognized $13.7$15.5 million and $13.7 million of discrete tax expense in the fourth quarter of 2018 and 2017 related to non-operatingrespectively. Of this total, tax benefits of $1.2 million and non-regulated property.
This amount results$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 remeasurementremeasurements of deferred tax assets and liabilities related to regulated utility property of $17.0 million and $135.2 million wasat December 31, 2018 and 2017 were recorded as a regulatory liability, which was aliabilities and were non-cash adjustment. Additional time is required to finalize remeasurement effects in accordance with GAAP.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 any futuresubsequent conversions will not be reversed. InDuring 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.
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Tax expense / (benefit) | | $ | 0.2 |
| | $ | (9.6 | ) | | $ | 6.3 |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | (9.6 | ) |
Uncertain Tax Positions
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| | | | | | | |
| $ in millions | | |
| Balance at December 31, 2015 | $ | 3.0 |
| |
| Calendar 2016 | | |
| Tax positions taken during prior period | 2.2 |
| |
| Lapse of Statute of Limitations | (1.5 | ) | |
| Balance at December 31, 2016 | 3.7 |
| $ | 3.7 |
|
| Calendar 2017 | | |
| Tax positions taken during prior period | — |
| — |
|
| Lapse of Statute of Limitations | (0.2 | ) | (0.2 | ) |
| Balance at December 31, 2017 | $ | 3.5 |
| 3.5 |
|
| Calendar 2018 | | |
| Tax positions taken during prior period | | — |
|
| Lapse of Statute of Limitations | | — |
|
| Balance at December 31, 2018 | | $ | 3.5 |
|
Of the December 31, 20172018 balance of unrecognized tax benefits, $0.9$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 109 – Benefit Plans
Defined contribution plansContribution 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 $2,300$2,400 for 20172018 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 and $4.9 million infor the years ended December 31, 2018, 2017 2016 and 2015,2016, 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. For 2017, the annual bonus amount is yet to be determined and paid; pending the results of negotiations with the bargaining unit.
Defined benefit plBenefit 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. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.
Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan 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 benefitsBenefits
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 and $15.8 million at
December 31, 20172018 and 2016,2017, 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, 20172018 and 2016.2017. 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 $1.1$1.8 million and $1.3$1.1 million of costs billed to the service companyService Company for the years ended December 31, 20172018 and 2016.2017.
| | | $ in millions | | Years ended December 31, | | Years ended December 31, |
| Change in benefit obligation | | 2017 | | 2016 | | 2018 | | 2017 |
| Benefit obligation at January 1 | | $ | 419.6 |
| | $ | 410.8 |
| | $ | 436.9 |
| | $ | 419.6 |
|
| Service cost | | 5.7 |
| | 5.7 |
| | 6.1 |
| | 5.7 |
|
| Interest cost | | 14.2 |
| | 14.7 |
| | 13.8 |
| | 14.2 |
|
| Plan amendments | | | 5.1 |
| | — |
|
| Plan curtailment | | 3.0 |
| | 2.5 |
| | — |
| | 3.0 |
|
| Actuarial loss | | 28.1 |
| | 9.0 |
| |
| Actuarial (gain) / loss | | | (34.6 | ) | | 28.1 |
|
| Benefits paid | | (33.7 | ) | | (23.1 | ) | | (40.8 | ) | | (33.7 | ) |
| Benefit obligation at December 31 | | 436.9 |
| | 419.6 |
| | 386.5 |
| | 436.9 |
|
| | | | | | | | | |
| Change in plan assets | | | | | | | | |
| Fair value of plan assets at January 1 | | 341.0 |
| | 345.4 |
| | 357.5 |
| | 341.0 |
|
| Actual return on plan assets | | 44.8 |
| | 13.3 |
| | (11.7 | ) | | 44.8 |
|
| Employer contributions | | 5.4 |
| | 5.4 |
| | 7.9 |
| | 5.4 |
|
| Benefits paid | | (33.7 | ) | | (23.1 | ) | | (40.8 | ) | | (33.7 | ) |
| Fair value of plan assets at December 31 | | 357.5 |
| | 341.0 |
| | 312.9 |
| | 357.5 |
|
| | | | | | | | | |
| Unfunded status of plan | | $ | (79.4 | ) | | $ | (78.6 | ) | | $ | (73.6 | ) | | $ | (79.4 | ) |
| |
| |
| |
| |
|
| | | December 31, | | December 31, |
| Amounts recognized in the Balance sheets | | 2017 | | 2016 | | 2018 | | 2017 |
| Current liabilities | | $ | (0.4 | ) | | $ | (0.4 | ) | | $ | (0.4 | ) | | $ | (0.4 | ) |
| Non-current liabilities | | (79.0 | ) | | (78.2 | ) | | (73.2 | ) | | (79.0 | ) |
| Net liability at end of year | | $ | (79.4 | ) | | $ | (78.6 | ) | | $ | (73.6 | ) | | $ | (79.4 | ) |
| | | | | | | | | |
| Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax | | | | | | | | |
| Components: | | | | | | | | |
| Prior service cost | | $ | 4.9 |
| | $ | 8.8 |
| | $ | 9.1 |
| | $ | 4.9 |
|
| Net actuarial loss | | 111.4 |
| | 108.9 |
| | 103.3 |
| | 111.4 |
|
| Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax | | $ | 116.3 |
| | $ | 117.7 |
| | $ | 112.4 |
| | $ | 116.3 |
|
| Recorded as: | |
| |
| |
| |
|
| Regulatory asset | | $ | 92.1 |
| | $ | 97.1 |
| | $ | 87.2 |
| | $ | 92.1 |
|
| Accumulated other comprehensive income | | 24.2 |
| | 20.6 |
| | 25.2 |
| | 24.2 |
|
| Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax | | $ | 116.3 |
| | $ | 117.7 |
| | $ | 112.4 |
| | $ | 116.3 |
|
The accumulated benefit obligation for our defined benefit pension plans was $428.3$378.7 million and $409.2$428.3 million at December 31, 2018 and 2017, and 2016, respectively.
The net periodic benefit cost of the pension plans was:
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Service cost | | $ | 5.7 |
| | $ | 5.7 |
| | $ | 7.1 |
| | $ | 6.1 |
| | $ | 5.7 |
| | $ | 5.7 |
|
| Interest cost | | 14.2 |
| | 14.7 |
| | 17.3 |
| | 13.8 |
| | 14.2 |
| | 14.7 |
|
| Expected return on assets | | (22.8 | ) | | (22.8 | ) | | (22.6 | ) | | (21.2 | ) | | (22.8 | ) | | (22.8 | ) |
Plan curtailment | | 4.1 |
| | 3.8 |
| | — |
| | — |
| | 4.1 |
| | 3.8 |
|
| Amortization of unrecognized: | | | | | | | | | | | | |
| Actuarial loss | | 5.3 |
| | 4.3 |
| | 5.8 |
| | 6.4 |
| | 5.3 |
| | 4.3 |
|
| Prior service cost | | 1.1 |
| | 1.8 |
| | 2.0 |
| | 0.9 |
| | 1.1 |
| | 1.8 |
|
| Net periodic benefit cost | | $ | 7.6 |
| | $ | 7.5 |
| | $ | 9.6 |
| | $ | 6.0 |
| | $ | 7.6 |
| | $ | 7.5 |
|
| | | | | | | | | | | | | |
| Rates relevant to each year's expense calculations | | | | | | | | | | | | |
| Discount rate | | 4.28 | % | | 4.49 | % | | 4.02 | % | | 3.66 | % | | 4.28 | % | | 4.49 | % |
| Expected return on plan assets | | 6.50 | % | | 6.50 | % | | 6.50 | % | | 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, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Net actuarial loss / (gain) | | $ | 9.1 |
| | $ | 20.9 |
| | $ | (3.0 | ) | |
| Prior service cost | | — |
| | — |
| | — |
| |
| Plan curtailment | | (4.1 | ) | | (3.8 | ) | | — |
| |
| Net actuarial loss | | | $ | 3.4 |
| | $ | 9.1 |
| | $ | 20.9 |
|
Plan curtailment (a) | | | — |
| | (4.1 | ) | | (3.8 | ) |
| Reversal of amortization item: | | | | | | | | | | | | |
| Net actuarial loss | | (5.3 | ) | | (4.3 | ) | | (5.8 | ) | | (6.4 | ) | | (5.3 | ) | | (4.3 | ) |
| Prior service cost | | (1.1 | ) | | (1.8 | ) | | (2.0 | ) | | (0.9 | ) | | (1.1 | ) | | (1.8 | ) |
| Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities | | $ | (1.4 | ) | | $ | 11.0 |
| | $ | (10.8 | ) | | $ | (3.9 | ) | | $ | (1.4 | ) | | $ | 11.0 |
|
| | | | | | | | | | | | | |
| Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities | | $ | 6.2 |
| | $ | 18.5 |
| | $ | (1.2 | ) | | $ | 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. |
Estimated amounts that will be amortized from AOCI, Regulatory assetsSignificant Gains and Regulatory liabilities into net periodicLosses Related to Changes in the Benefit Obligation
The actuarial gain of $34.6 million decreased the benefit costs duringobligation for the year ended December 31, 2018 are:
|
| | | | |
| $ in millions | | Pension |
| Actuarial loss | | $ | 6.4 |
|
| Prior service cost | | $ | 0.9 |
|
Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
At December 31, 2017,2018, we are decreasingmaintaining our long-term rate of return assumption toof 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, 2017,2018, we have decreasedincreased our assumed discount rate to 3.66%4.35% from 4.28%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 20182019 pension expense of approximately $3.4$3.2 million. A one percent decrease in the rate of return assumption for pension would result in an increase in 20182019 pension expense of approximately $3.4$3.2 million. A 25-basis point increase in the discount rate for pension would result in a decrease of approximately
$0.6 $0.1 million to 20182019 pension expense. A 25-basis point decrease in the discount rate for pension would result in an increase of approximately $0.6$0.4 million to 20182019 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, 2017.2018. 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.
Effective January 1, 2016,Consistent with the requirements of FASC 715, we appliedapply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies for more information.
In future periods, differences in the actual return on pension 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 2016 and 20152016 were:
| | | Benefit Obligation Assumptions | | Pension | | Pension |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Discount rate for obligations | | 3.66% | | 4.28% | | 4.49% | | 4.35% | | 3.66% | | 4.28% |
| Rate of compensation increases | | 3.94% | | 3.94% | | 3.94% | | 3.94% | | 3.94% | | 3.94% |
Pension plan assetsPlan Assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.
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 2017:2018:
| | | | | Long-Term
Mid-Point
Target
Allocation | | Percentage of plan assets as of December 31, | | Long-Term
Mid-Point
Target
Allocation | | Percentage of plan assets as of December 31, |
| Asset category | | 2017 | | 2016 | | 2018 | | 2017 |
| Equity Securities | | 38% | | 35% | | 37% | | 38% | | 33% | | 35% |
| Debt Securities | | 56% | | 55% | | 53% | | 56% | | 58% | | 55% |
| Cash and Cash Equivalents | | | —% | | 1% | | —% |
| Real Estate | | 6% | | 10% | | 10% | | 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 |
| $ in millions | | Market Value 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. |
| |
| (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 | | $ in millions | | Market Value at December 31, 2017 | | Quoted prices
in active
markets for
identical assets | | Significant
observable
inputs | | Significant
unobservable
inputs | | Market Value 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) | | | | (Level 1) | | (Level 2) | | (Level 3) |
| Mutual funds: | | | | | | | | | | | | | | | | |
U.S. equities (a) | | $ | 78.2 |
| | $ | 78.2 |
| | $ | — |
| | $ | — |
| | $ | 78.2 |
| | $ | 78.2 |
| | $ | — |
| | $ | — |
|
International equities (a) | | 46.3 |
| | 46.3 |
| | — |
| | — |
| | 46.3 |
| | 46.3 |
| | — |
| | — |
|
Fixed income (b) | | 163.3 |
| | 163.3 |
| | — |
| | — |
| | 163.3 |
| | 163.3 |
| | — |
| | — |
|
| Fixed income securities: | | | | | | | | | | | | | | | | |
| U.S. Treasury securities | | 33.5 |
| | 33.5 |
| | — |
| | — |
| | 33.5 |
| | 33.5 |
| | — |
| | — |
|
Other investments: | | | | | | | | | | | | | | | | |
Core property collective fund (c) | | 36.2 |
| | — |
| | 36.2 |
| | — |
| | 36.2 |
| | — |
| | 36.2 |
| | — |
|
| Total pension plan assets | | $ | 357.5 |
| | $ | 321.3 |
| | $ | 36.2 |
| | $ | — |
| | $ | 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. |
The fair values of our pension plan assets at December 31, 2016 by asset category are as follows:
|
| | | | | | | | | | | | | | | | |
| Fair Value Measurements for Pension Plan Assets at December 31, 2016 |
| $ in millions | | Market Value at December 31, 2016 | | 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) | | $ | 81.4 |
| | $ | 81.4 |
| | $ | — |
| | $ | — |
|
International equities (a) | | 44.4 |
| | 44.4 |
| | — |
| | — |
|
Fixed income (b) | | 151.1 |
| | 151.1 |
| | — |
| | — |
|
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 31.0 |
| | 31.0 |
| | — |
| | — |
|
Other investments: (c) | | | | | | | | |
| Core property collective fund | | 33.1 |
| | — |
| | 33.1 |
| | — |
|
| Common collective fund | | — |
| | — |
| | — |
| | — |
|
| Total pension plan assets | | $ | 341.0 |
| | $ | 307.9 |
| | $ | 33.1 |
| | $ | — |
|
| |
(a) | This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
| |
(b) | This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
| |
(c) | This category represents a property fund that invests in commercial real estate. 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 fundingFunding
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 2016 and 2015.2016.
We expect to make contributions of $0.4 million to our SERP in 20182019 to cover benefit payments. We madealso expect to make contributions of $7.5 million to our pension plan during January 2018.2019.
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 99%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 $7.5$5.4 million in 2018,2019, which includes $2.2$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 | | Pension |
| 2018 | | $ | 28.4 |
| |
| 2019 | | $ | 28.2 |
| | $ | 26.7 |
|
| 2020 | | $ | 27.9 |
| | $ | 26.5 |
|
| 2021 | | $ | 27.6 |
| | $ | 26.3 |
|
| 2022 | | $ | 27.3 |
| | $ | 26.0 |
|
| 2023 - 2027 | | $ | 131.3 |
| |
| 2023 | | | $ | 25.9 |
|
| 2024 - 2028 | | | $ | 125.1 |
|
Note 1110 – 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. 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, 2017.2018.
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 ofon 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, 2017,2018, DPL’s leverage ratio was at 1.501.47 to 1.00 and DPL’s senior long-term debt rating from all threea major credit rating agenciesagency was below investment grade. As a result, as of December 31, 2017,2018, 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 250,000,00050,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2017.2018. All common shares are held by DP&L’s parent, DPL.
As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. After the fixed-asset impairments recorded during 2016 and 2017, DP&L's equity ratio was 33% and its retained earnings balance was negative as of December 31, 2017. It is unknown what impact, if any, this will have on DP&L.
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 98 – Income Taxes for additional information.
Note 1211 – Contractual Obligations, Commercial Commitments and Contingencies
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 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, 2017,2018, DPL had $38.1$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 and $2.3 million at December 31, 2017 and 2016, respectively.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, 2017,2018, DP&L could be responsible for the repayment of 4.9%, or $70.6$68.1 million, of a $1,440.8$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. At DecemberOne 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, 2017, we2018. We do not expect these events to have no knowledgea material impact on our financial condition, results of such a default.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, 2017,2018, these include:
| | | | | Payments due in: | | Payments due in: |
| $ in millions | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years |
| Electricity purchase commitments | | $ | 370.9 |
| | $ | 178.5 |
| | $ | 171.2 |
| | $ | 21.2 |
| | $ | — |
| | $ | 209.4 |
| | $ | 139.5 |
| | $ | 69.9 |
| | $ | — |
| | $ | — |
|
Coal and limestone contracts (a) | | $ | 54.9 |
| | $ | 54.9 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Purchase orders and other contractual obligations | | $ | 73.0 |
| | $ | 18.9 |
| | $ | 27.1 |
| | $ | 27.0 |
| | $ | — |
| | $ | 40.2 |
| | $ | 11.4 |
| | $ | 14.8 |
| | $ | 14.0 |
| | $ | — |
|
| |
(a) | Total at DPL operated units.
|
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.
Coal contracts:
DPL, through its subsidiary AES Ohio Generation, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2017, a majority of our future committed coal obligations are with one supplier. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year. As a result of our planned shutdown of our Stuart and Killen generating stations, our commitments for coal and limestone do not extend past 2018.
Purchase orders and other contractual obligations:
At December 31, 2017,2018, 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..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 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, 2017,2018, cannot be reasonably determined.
Environmental Matters
DPL’s facilities and operations are subject to a wide range of federal, state and local environmental regulationslaws, rules and laws.regulations. The environmental issues that may affect us include: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.DPL installed emission control technology and is taking other measures to comply with required and anticipated reductions. As AES Ohio Generation is now operating these facilities, it is continuing to comply with these requirements; |
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 the operationour results of the power stations.operations, financial condition or cash flows.
Note 1312 – Related Party Transactions
Service Company
Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services 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 plansPlans
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 2016 and 2015,2016, 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 and options to purchase shares of AES common stock, however no stock options were granted in 2016. All such components vest ratably over a three-year period and the terms of the AES restricted stock units issued prior to 2011 also include a two-year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years are not subject to a two-year holding period. In addition, theThe 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 2016 and 20152016 was $0.4 million, $0.5$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 theseour related party transactions:
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Transactions with the Service Company | | | | | | | | | | | | |
| Charges for services provided | | $ | 46.5 |
| | $ | 42.8 |
| | $ | 36.0 |
| | $ | 41.0 |
| | $ | 46.5 |
| | $ | 42.8 |
|
| Charges to the Service Company | | $ | 4.2 |
| | $ | 4.6 |
| | $ | 6.2 |
| | $ | 4.9 |
| | $ | 4.2 |
| | $ | 4.6 |
|
| Transactions with other AES affiliates: | | | | | | | | | | | | |
| Payments for health, welfare and benefit plans | | $ | 15.4 |
| | $ | 9.6 |
| | $ | 15.5 |
| | $ | 7.9 |
| | $ | 15.4 |
| | $ | 9.6 |
|
| Consulting services | | | $ | 2.0 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | |
| Balances with related parties: | | At December 31, 2017 | | At December 31, 2016 | | | | At December 31, 2018 | | At December 31, 2017 | | |
| Net payable to the Service Company | | $ | (3.9 | ) | | $ | (2.0 | ) | | | | $ | (4.8 | ) | | $ | (3.9 | ) | | |
| Net payable to other AES affiliates | | $ | (0.6 | ) | | $ | (2.5 | ) | | | | $ | (0.5 | ) | | $ | (0.6 | ) | | |
DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounted to $0.3$0.2 million and $0.3 million at December 31, 20172018 and 2016,2017, 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, 20172018 and 2016,2017, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 87 – DebtLong-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 taxesTaxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. Under this agreement, DPL had a net payable balance of $0.0 million at December 31, 2016, respectively, which is recorded in Accrued taxes on the accompanying Consolidated Balance Sheets. 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 98 – Income Taxes for more information.
Note 1413 – Business Segments
Beginning with the second quarter of 2018, DPL currentlyhas 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 twoonly one reportable operating segments,segment, the T&D segment and the GenerationUtility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of DPL and is the most relevant measure considered in DPL’s internal evaluation of the financial performance of its segments. The segments areUtility segment is discussed further below:
Transmission and DistributionUtility Segment
The T&DUtility 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 521,000525,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs. The T&DUtility segment includes revenues and costs associated with DP&L'sour 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 Coal generating facilities,EGU, which were eitherwas closed or sold in prior periods. As these2013. These assets weredid not transferredtransfer to AES Ohio Generation as part of DP&L's Generation Separation on October 1, 2017. Thus, they are grouped withwithin the T&D assetsUtility segment for segment reporting purposes. In addition, regulatory deferrals and collections, which include fuel deferrals in historical periods, are included in the T&DUtility segment.
Generation Segment
The Generation segment is comprised of AES Ohio Generation and the historical results of DP&L's electric generation business prior to Generation Separation. Beginning in 2001, Ohio law gave consumers the right to choose the electric generation supplier from whom they purchase retail generation services. AES Ohio Generation owns and operates coal-fired and peaking generating facilities and sells its generated energy and capacity into the PJM wholesale market. The 2015 Generation segment results also include sales to DPLER and to the T&D segment for SSO customers.
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 each of DPL’s reportable business segments:segment:
|
| | | | | | | | | | | | | | | | | | | | |
| $ in millions | | T&D | | Generation | | Other | | Adjustments and Eliminations | | DPL Consolidated |
| Year ended December 31, 2017 |
| Revenues from external customers | | $ | 718.9 |
| | $ | 507.9 |
| | $ | 10.1 |
| | $ | — |
| | $ | 1,236.9 |
|
| Intersegment revenues | | 1.1 |
| | — |
| | 4.4 |
| | (5.5 | ) | | — |
|
| Total revenues | | $ | 720.0 |
|
| $ | 507.9 |
| | $ | 14.5 |
| | $ | (5.5 | ) | | $ | 1,236.9 |
|
| | | | | | | | | | | |
| Depreciation and amortization | | $ | 75.3 |
| | $ | 20.9 |
| | $ | 10.7 |
| | $ | — |
| | $ | 106.9 |
|
| Fixed-asset impairment (Note 15) | | $ | — |
| | $ | 66.3 |
| | $ | 109.5 |
| | $ | — |
| | $ | 175.8 |
|
| Interest expense | | $ | 30.5 |
| | $ | 0.1 |
| | $ | 79.5 |
| | $ | — |
| | $ | 110.1 |
|
| Income / (loss) from continuing operations before income tax | | $ | 88.5 |
| | $ | (18.5 | ) | | $ | (189.9 | ) | | $ | — |
| | $ | (119.9 | ) |
| | | | | | | | | | | |
| Cash capital expenditures | | $ | 85.6 |
| | $ | 31.3 |
| | $ | 4.6 |
| | $ | — |
| | $ | 121.5 |
|
| | | | | | | | | | | |
| Total assets (end of year) | | $ | 1,689.4 |
| | $ | 275.0 |
| | $ | 468.0 |
| | $ | (383.2 | ) | | $ | 2,049.2 |
|
| | | $ in millions | | T&D | | Generation | | Other | | Adjustments and Eliminations | | DPL Consolidated | | Utility | | Other (a) | | Adjustments and Eliminations | | DPL Consolidated |
| Year ended December 31, 2016 | |
| Year ended December 31, 2018 | | Year ended December 31, 2018 |
| Revenues from external customers | | $ | 806.7 |
| | $ | 611.5 |
| | $ | 9.1 |
| | $ | — |
| | $ | 1,427.3 |
| | $ | 737.8 |
| | $ | 38.1 |
| | $ | — |
| | $ | 775.9 |
|
| Intersegment revenues | | 1.3 |
| | — |
| | 5.7 |
| | (7.0 | ) | | — |
| | 0.9 |
| | 2.9 |
| | (3.8 | ) | | — |
|
| Total revenues | | $ | 808.0 |
| | $ | 611.5 |
| | $ | 14.8 |
| | $ | (7.0 | ) | | $ | 1,427.3 |
| | $ | 738.7 |
|
| $ | 41.0 |
| | $ | (3.8 | ) | | $ | 775.9 |
|
| | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | $ | 71.0 |
| | $ | 55.4 |
| | $ | 5.9 |
| | $ | — |
| | $ | 132.3 |
| | $ | 74.5 |
| | $ | (1.4 | ) | | $ | — |
| | $ | 73.1 |
|
| Fixed-asset impairment (Note 15) | | $ | — |
| | $ | 1,353.5 |
| | $ | (494.5 | ) | | $ | — |
| | $ | 859.0 |
| |
| Fixed-asset impairment | | | $ | — |
| | $ | 2.8 |
| | $ | — |
| | $ | 2.8 |
|
| Interest expense | | $ | 25.4 |
| | $ | 0.4 |
| | $ | 82.2 |
| | $ | (0.3 | ) | | $ | 107.7 |
| | $ | 27.3 |
| | $ | 70.7 |
| | $ | — |
| | $ | 98.0 |
|
| Income / (loss) from continuing operations before income tax | | $ | 143.0 |
| | $ | (1,353.9 | ) | | $ | 417.6 |
| | $ | — |
| | $ | (793.3 | ) | | $ | 104.4 |
| | $ | (72.5 | ) | | $ | — |
| | $ | 31.9 |
|
| | | | | | | | | | | | | | | | | | | |
| Cash capital expenditures | | $ | 83.4 |
| | $ | 64.2 |
| | $ | 0.9 |
| | $ | — |
| | $ | 148.5 |
| | $ | 93.1 |
| | $ | 10.5 |
| | $ | — |
| | $ | 103.6 |
|
| | | | | | | | | | | | | | | | | | | |
| Total assets (end of year) | | $ | 1,710.5 |
| | $ | 472.3 |
| | $ | 673.6 |
| | $ | (437.2 | ) | | $ | 2,419.2 |
| | $ | 1,819.6 |
| | $ | 545.9 |
| | $ | (482.4 | ) | | $ | 1,883.1 |
|
| | | $ in millions | | T&D | | Generation | | Other | | Adjustments and Eliminations | | DPL Consolidated | | Utility | | Other (a) | | Adjustments and Eliminations | | DPL Consolidated |
| Year ended December 31, 2015 | |
| Year ended December 31, 2017 | | Year ended December 31, 2017 |
Revenues from external customers (b) | | $ | 855.5 |
| | $ | 770.3 |
| | $ | 6.7 |
| | $ | (19.7 | ) | | $ | 1,612.8 |
| | $ | 718.9 |
| | $ | 25.0 |
| | $ | — |
| | $ | 743.9 |
|
| Intersegment revenues | | 1.5 |
| | 186.6 |
| | 4.2 |
| | (192.3 | ) | | — |
| | 1.1 |
| | 4.4 |
| | (5.5 | ) | | — |
|
| Total revenues | | $ | 857.0 |
| | $ | 956.9 |
| | $ | 10.9 |
| | $ | (212.0 | ) | | $ | 1,612.8 |
| | $ | 720.0 |
| | $ | 29.4 |
| | $ | (5.5 | ) | | $ | 743.9 |
|
| | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | $ | 71.5 |
| | $ | 72.6 |
| | $ | (9.5 | ) | | $ | — |
| | $ | 134.6 |
| | $ | 75.3 |
| | $ | 0.8 |
| | $ | — |
| | $ | 76.1 |
|
| Goodwill impairment (Note 7) | | $ | — |
| | $ | — |
| | $ | 317.0 |
| | $ | — |
| | $ | 317.0 |
| |
| Interest expense | | $ | 29.8 |
| | $ | 2.9 |
| | $ | 87.4 |
| | $ | (0.3 | ) | | $ | 119.8 |
| | $ | 30.5 |
| | $ | 79.5 |
| | $ | — |
| | $ | 110.0 |
|
| Income / (loss) from continuing operations before income tax | | $ | 188.1 |
| | $ | (28.7 | ) | | $ | (390.8 | ) | | $ | — |
| | $ | (231.4 | ) | | $ | 88.5 |
| | $ | (95.0 | ) | | $ | — |
| | $ | (6.5 | ) |
| | | | | | | | | | | | | | | | | | | |
| Cash capital expenditures | | $ | 98.3 |
| | $ | 35.2 |
| | $ | 3.7 |
| | $ | — |
| | $ | 137.2 |
| | $ | 85.6 |
| | $ | 35.9 |
| | $ | — |
| | $ | 121.5 |
|
| | | | | | | | | | | | | | | | | | | |
Total assets (end of year) (a) | | $ | 1,688.8 |
| | $ | 1,805.0 |
| | $ | 1,170.3 |
| | $ | (1,339.4 | ) | | $ | 3,324.7 |
| |
| Total assets (end of year) | | | $ | 1,695.9 |
| | $ | 736.5 |
| | $ | (383.2 | ) | | $ | 2,049.2 |
|
|
| | | | | | | | | | | | | | | | |
| $ in millions | | Utility | | Other (a) | | Adjustments and Eliminations | | DPL Consolidated |
| Year ended December 31, 2016 |
| Revenues from external customers | | $ | 806.7 |
| | $ | 27.5 |
| | $ | — |
| | $ | 834.2 |
|
| Intersegment revenues | | 1.3 |
| | 5.7 |
| | (7.0 | ) | | — |
|
| Total revenues | | $ | 808.0 |
| | $ | 33.2 |
| | $ | (7.0 | ) | | $ | 834.2 |
|
| | | | | | | | | |
| Depreciation and amortization | | $ | 71.0 |
| | $ | 2.6 |
| | $ | — |
| | $ | 73.6 |
|
| Fixed-asset impairment | | $ | — |
| | $ | 23.9 |
| | $ | — |
| | $ | 23.9 |
|
| Interest expense | | $ | 25.4 |
| | $ | 82.3 |
| | $ | (0.3 | ) | | $ | 107.4 |
|
| 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) | Includes"Other" includes Cash capital expenditures and Total assets held-for-sale related to the saleassets of DPLER.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:
|
| | | | | | | | | | | | | | | | |
| $ in millions | | Utility | | Other | | Adjustments and Eliminations | | Total |
| | | Year ended December 31, 2018 |
| Retail Revenue | | | | | | | | |
| Retail revenue from contracts with customers | | $ | 625.8 |
| | $ | — |
| | $ | (1.0 | ) | | $ | 624.8 |
|
Other retail revenues (a) | | 32.1 |
| | — |
| | — |
| | 32.1 |
|
| Wholesale Revenue | | | | | | | | |
| Wholesale revenue from contracts with customers | | 29.9 |
| | 22.1 |
| | — |
| | 52.0 |
|
| RTO revenue | | 43.1 |
| | 0.1 |
| | — |
| | 43.2 |
|
| RTO capacity revenues | | 7.8 |
| | 6.6 |
| | — |
| | 14.4 |
|
Other revenues from contracts with customers (b) | | — |
| | 9.4 |
| | — |
| | 9.4 |
|
| Other revenues | | — |
| | 2.8 |
| | (2.8 | ) | | — |
|
| Total revenues | | $ | 738.7 |
| | $ | 41.0 |
| | $ | (3.8 | ) | | $ | 775.9 |
|
| |
| (a) | Other retail revenue primarily includes alternative revenue programs not accounted for under FASC 606. |
| |
| (b) | Wholesale revenueOther revenues from contracts with customers primarily includes revenues for the T&D segment in 2015 includes OVEC revenue of $19.7 million that was previously netted in purchased power. The impact of this netting adjustment is included in the Adjustments and Eliminations column in the table above but has no impact on consolidated revenues or Income / (loss) from continuing operations before income tax.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 – Fixed-asset ImpairmentsDiscontinued Operations
DuringOn December 8, 2017, DPL and AES Ohio Generation completed the yearssale 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, 2016 and 2015,2017. On March 27, 2018, DPL had the following fixed-asset impairments:
|
| | | | | | | | | | | | | | |
| | | | | Years ended December 31, |
| $ in millions | | Measurement Date | | 2017 | | 2016 | | 2015 |
| AES Ohio Generation peakers | | December 31, 2017 | | $ | 109.4 |
| | $ | — |
| | $ | — |
|
| Stuart | | March 31, 2017 | | 39.1 |
| | — |
| | — |
|
| Killen | | March 31, 2017 | | 27.3 |
| | — |
| | — |
|
| Killen | | December 31, 2016 | | — |
| | 75.4 |
| | — |
|
| Stuart | | December 31, 2016 | | — |
| | 228.5 |
| | — |
|
| Miami Fort | | December 31, 2016 | | — |
| | 149.4 |
| | — |
|
| Zimmer | | December 31, 2016 | | — |
| | 144.7 |
| | — |
|
| Conesville | | December 31, 2016 | | — |
| | 23.9 |
| | — |
|
| Hutchings peaking facilities | | December 31, 2016 | | — |
| | 1.6 |
| | — |
|
| Killen | | June 30, 2016 | | — |
| | 230.8 |
| | — |
|
| Certain peaking facilities | | June 30, 2016 | | — |
| | 4.7 |
| | — |
|
| Total impairment loss | | | | $ | 175.8 |
| | $ | 859.0 |
| | $ | — |
|
and AES Ohio Generation peakerscompleted 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, –DPLIn December 2017, and AES Ohio Generation signed an agreement for the sale of its peaking and diesel generation assets. As a result of this transaction, DPL recognized an impairment of fixed assets in the amount of $109.4 million.
Stuart and Killen, March 17, 2017 – On March 17, 2017, the Board of Directors of DP&L approved the retirement ofretired the Stuart Station coal-fired and diesel-fired generating units and the Killen Station coal-fired generating unit and combustion turbine, (collectively,as planned. Consequently, in the “Facilities”)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 or before JuneJanuary 1, 2018.2016, DPL closed on the sale of DPLER, its competitive retail business. The co-ownerssale agreement was signed on December 28, 2015, and DPL received $75.5 million of these facilities agreedrestricted 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.
The following table summarizes the major categories of assets and liabilities at the dates indicated:
|
| | | | | | | | |
| $ in millions | | December 31, 2018 | | December 31, 2017 |
| Restricted cash | | $ | — |
| | $ | 1.5 |
|
| Accounts receivable, net | | 4.0 |
| | 37.9 |
|
| Inventories | | — |
| | 19.4 |
|
| Taxes applicable to subsequent years | | 2.3 |
| | 7.4 |
|
| Other prepayments and current assets | | 2.4 |
| | 17.4 |
|
| Property, plant & equipment, net | | — |
| | 232.2 |
|
| Intangible assets, net | | 5.3 |
| | 5.5 |
|
| Other deferred assets | | — |
| | 0.6 |
|
| 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 proceedmaintain 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 this plan of retirement. We performed a long-lived asset impairment analysisthat 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 determined that$0.5 million for the carrying amounts of the Facilities were not recoverable. The asset groups of Stuart Stationyears December 31, 2017 and Killen Station were determined to have fair values of $3.3 million and $7.9 million, respectively, using the discounted cash flows under the income approach. As a result, we recognized asset impairment expense of $39.1 million and $27.3 million for Stuart Station and Killen Station,2016, respectively.
AROs of Discontinued Operations
Additionally, as a result of the decision to retire the Facilities by June 1, 2018, we concluded that inventory at these Facilities is considered obsolete. As a result, we recognized a loss on disposal ofDPL's $9.8 million and $6.4 million forretired Stuart Station and Killen Station inventories, respectively, during the first quartergenerating facilities continue to carry ARO liabilities consisting primarily of 2017, which is recorded in Loss on assetriver intake and discharge structures, coal unloading facilities, landfills, and ash disposal in the Consolidated Statements of Operations.
Killen, Stuart, Miami Fort, Zimmer, Conesville and Hutchings, December 31, 2016 –Duringfacilities. In the fourth quarter of 2016, we tested2018, DPL reduced the recoverability of our long-lived coal-fired generation assets and one gas-fired peaking plant. Additional uncertainty aroundARO liability related to the useful life of 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 ESP proceedings along with lower expectationsand its co-owners of forward dark spreads and capacity prices beyond the cleared period were collectively determinedretired Beckjord Facility agreed to be an impairment indicator for these assets. Market information indicating that there was a significant decreasetransfer their interests in the fair value ofretired Facility to a third party, including their obligations to remediate the Miami FortFacility and Zimmer stations was determined to be an indicator of impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the gas-fired peaking plant, significant incremental capital expenditures relative to its fair value along with the fact that an impairment charge was previously taken at this facility in Q2 2016, were collectively determined to be an impairment indicator for this asset. We performed a long-lived asset impairment analysis for each of these asset groups and determined that their carrying amounts were not recoverable. The Killen, Stuart, Miami Fort, Zimmer and Conesville coal-fired facility asset groupssite, and the Hutchings gas-fired peaking plant asset group were determined to have a fair value of $42.8 million, $57.4 million, $36.5 million, $23.7 million, $1.1 million and $1.6 million, respectively, using the market approach for Miami Fort and Zimmer and the income approach for the remaining asset groups.transfer occurred on that same date. As a result, DPL recognized a total pre-tax asset impairment expenseloss on the transfer of $623.5 million.
Killen and DP&L peaking facilities, June 30, 2016 –During the second quarter of 2016, we tested the recoverability of our long-lived assets at certain of our generation facilities at DP&L. A ruling by the Supreme Court of Ohio on June 20, 2016, lower expectation of future capacity revenue resulting from the most recent PJM capacity auction and a higher anticipated level of environmental compliance costs resulting from third party studies were collectively determined to be an impairment indicator for these assets. We performed a long-lived asset impairment analysis and determined that the carrying amounts of Killen and certain DP&L peaking generating facilities were not recoverable. The asset groups of Killen and these DP&L peaking generating facilities were determined to have fair values of $84.3$11.7 million and $5.2made cash expenditures of $14.5 million, respectively, usinginclusive of cash expenditures for the discounted cash flows undertransfer charges. The Beckjord Facility was retired in 2014, and, as such, the income approach. As a result, DPL recognized an asset impairment expense of $230.8 million/ (loss) from continuing operations before income tax related to the Beckjord Facility was immaterial for the years ended December 31, 2018, 2017 and $4.7 million for Killen and these DP&L peaking generating facilities, respectively.2016, excluding the loss on transfer noted above. Prior to the transfer, the Beckjord Facility was included in the Utility segment.
Note 16 – Discontinued Operations
On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015, and DPL 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.
Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Consolidated Statements of Operations for the years ended December 31, 2016 and 2015.
The following table summarizes the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:
|
| | | | | | | | |
| | | Years ended December 31, |
| $ in millions | | 2016 | | 2015 |
| Revenues | | $ | — |
| | $ | 340.9 |
|
| Cost of revenues | | — |
| | (307.0 | ) |
| Operating expenses | | (0.7 | ) | | (22.5 | ) |
| Income / (loss) from discontinued operations before income tax | | (0.7 | ) | | 11.4 |
|
| Gain from disposal of discontinued operations | | 49.2 |
| | — |
|
| Income tax expense / (benefit) from discontinued operations | | 19.2 |
| | (1.0 | ) |
| Income from discontinued operations | | $ | 29.3 |
| | $ | 12.4 |
|
Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $(0.7) million and $35.8 million for the years ended December 31, 2016 and 2015, respectively. Cash flows from investing activities for discontinued operations were $75.5 million and $0.5 million for the years ended December 31, 2016 and 2015, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented.
Note 17 – Assets and Liabilities Held-For-Sale and Dispositions
Assets and liabilities held-for-sale
On December 15, 2017, DPL and AES Ohio Generation entered into an asset purchase agreement with Kimura Power, LLC, as Buyer (“Kimura Power”), and, for certain limited purposes provided therein, Rockland Power Partners III, LP, as Guarantor, pursuant to which AES Ohio Generation will, subject to the terms and conditions in the asset purchase agreement, sell to Kimura Power the Peaker assets. The Peaker assets are being sold for $241.0 million in cash. The cash purchase price is subject to adjustments at closing based on working capital, capacity commitments and timing of the closing of the transaction. The sale transaction is subject to regulatory approvals and other closing conditions. The FERC approved this transaction on February 9, 2018.Fixed-asset impairments
As a resultDuring the fourth quarter of entering into2016, we tested the asset purchase agreement, DPL recognized aggregaterecoverability 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 charges with respect to the Peaker assets of $109.4 million. For more information on these impairment charges, see Note 15 – Fixed-asset Impairments of Notes to DPL's Consolidated Financial Statements.
The assets and liabilities related to the Peaker assets were classified as held-for-sale as of December 31, 2017, but the Peaker assets did not meet the criteria to be reported as discontinued operations. The following table summarizes the major classes of assets and liabilities classified as held-for-sale as of December 31, 2017:
|
| | | | |
| $ in millions | | December 31, 2017 |
| Assets | | |
| Accounts receivable, net | | $ | 3.8 |
|
| Inventories | | 7.6 |
|
| Taxes applicable to subsequent years | | 4.9 |
|
| Property, plant & equipment, net | | 233.7 |
|
| Other assets | | 0.3 |
|
| Total assets of the disposal group classified as held-for-sale in the balance sheet | | $ | 250.3 |
|
| | | |
| Liabilities | | |
| Accounts payable | | $ | 3.9 |
|
| Accrued taxes | | 3.6 |
|
| Taxes payable | | 4.9 |
|
| Asset retirement obligations | | 0.6 |
|
| Other liabilities | | 0.2 |
|
| Total liabilities of the disposal group classified as held-for-sale in the balance sheet | | $ | 13.2 |
|
The Peaker assets' results of operations are reflected within continuing operations in the Consolidated Statements of Operations. The income from continuing operations before income tax for the Peaker assets was $16.9 million, $20.0 million and $23.9 million (excludingConesville asset group. We performed a long-lived asset impairment charges of $109.4 million, $1.3 million and $0.0 million, respectively)analysis for the years ended December 31, 2017, 2016,Conesville asset group and 2015, respectively.determined that its carrying amount was not recoverable. The Peaker assets are included inConesville coal-fired facility asset group was determined to have a fair value of $1.1 million using the Generation segment.
Dispositions
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 to Dynegy Zimmer and Dynegy Miami Fort, indirect wholly-owned subsidiaries of Dynegy. On that date, AES Ohio Generation received $50.0 million in cash, plus an amount in cash equal to $20.1 million as an estimated purchase price adjustment based on estimated amounts of certain pre-closing inventories, pre-paid and other amounts, employment benefits, insurance premiums, property taxes and other payables, which will be subject to a customary post-closing reconciliation. This transaction resulted in a gain on sale of $14.0 million for the year ended December 31, 2017. Prior to the sale, the Miami Fort and Zimmer stations were included in the Generation segment.
The results of operations of the Miami Fort and Zimmer stations are presented within continuing operations in the Consolidated Statements of Operations. The combined income / (loss) from continuing operations before income tax for the Miami Fort and Zimmer stations was $25.7 million (excluding gain on sale of $14.0 million), $(13.5) million (excluding impairment charges of $294.1 million) and $5.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.
Note 18 – Subsequent Event
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.approach. As a result, DPL estimates that it will recognize aggregaterecognized a total pre-tax loss on disposal chargesasset impairment expense of approximately $11.7$23.9 million.
During the year ended December 31, 2018, DPL recognized a total pre-tax asset impairment expense of $2.8 million and that cash expenditures of $15.0 million in the aggregate will be made, inclusive of cash expenditures for the disposal charges.Conesville asset group, as it was determined that additional amounts capitalized in 2018 were not recoverable.
FINANCIAL STATEMENTS
The Dayton Power and Light Company
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, 20172018 and 2016,2017, 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, 2017,2018, and the related notes and schedulesschedule (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, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172018 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 December 31, 2017 and 2016 audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America and our December 31, 2015 audit in accordance with the standards of the PCAOB.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.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2012.
Indianapolis, Indiana
February 26, 20182019
| | THE DAYTON POWER AND LIGHT COMPANY | | STATEMENTS OF OPERATIONS | |
| Statements of Operations | | Statements of Operations |
| | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Revenues | | $ | 720.0 |
| | $ | 808.0 |
| | $ | 857.0 |
| | $ | 738.7 |
| | $ | 720.0 |
| | $ | 808.0 |
|
| | | | | | | | | | | | | |
| Cost of revenues: | | | | | | | | | | | | |
| Net fuel costs | | 0.5 |
| | 5.3 |
| | (9.0 | ) | | 2.4 |
| | 0.5 |
| | 5.3 |
|
| Net purchased power cost | | 289.8 |
| | 316.7 |
| | 317.4 |
| | 301.3 |
| | 289.8 |
| | 316.7 |
|
| Total cost of revenues | | 290.3 |
| | 322.0 |
| | 308.4 |
| | 303.7 |
| | 290.3 |
| | 322.0 |
|
| | | | | | | | | | | | | |
| Gross margin | | 429.7 |
| | 486.0 |
| | 548.6 |
| | 435.0 |
| | 429.7 |
| | 486.0 |
|
| | | | | | | | | | | | | |
| Operating expenses: | | | | | | | | | | | | |
| Operation and maintenance | | 158.0 |
| | 179.3 |
| | 184.0 |
| | 139.7 |
| | 156.5 |
| | 178.4 |
|
| Depreciation and amortization | | 75.3 |
| | 71.0 |
| | 71.5 |
| | 74.5 |
| | 75.3 |
| | 71.0 |
|
| General taxes | | 76.3 |
| | 68.0 |
| | 70.8 |
| | 73.1 |
| | 76.3 |
| | 68.0 |
|
| Other, net | | (0.5 | ) | | (0.4 | ) | | 0.1 |
| |
| Loss / (gain) on asset disposal | | | 0.2 |
| | (0.5 | ) | | (0.4 | ) |
| Loss on disposal of business (Note 15) | | | 12.4 |
| | — |
| | — |
|
| Total operating expenses | | 309.1 |
| | 317.9 |
| | 326.4 |
| | 299.9 |
| | 307.6 |
| | 317.0 |
|
| | | | | | | | | | | | | |
| Operating income | | 120.6 |
| | 168.1 |
| | 222.2 |
| | 135.1 |
| | 122.1 |
| | 169.0 |
|
| | | | | | | | | | | | | |
| Other income / (expense), net | | | | | | | | | | | | |
| Investment income | | 0.3 |
| | 0.4 |
| | 0.3 |
| |
| Interest expense | | (30.5 | ) | | (24.7 | ) | | (28.9 | ) | | (27.3 | ) | | (30.5 | ) | | (24.7 | ) |
| Charge for early redemption of debt | | (1.1 | ) | | (0.5 | ) | | (4.8 | ) | | (0.6 | ) | | (1.1 | ) | | (0.5 | ) |
| Other income / (expense) | | (0.8 | ) | | 0.3 |
| | 0.2 |
| | (2.8 | ) | | (2.0 | ) | | (0.2 | ) |
| Total other expense, net | | (32.1 | ) | | (24.5 | ) | | (33.2 | ) | | (30.7 | ) | | (33.6 | ) | | (25.4 | ) |
| | | | | | | | | | | | | |
| Income from continuing operations before income tax | | 88.5 |
| | 143.6 |
| | 189.0 |
| | 104.4 |
| | 88.5 |
| | 143.6 |
|
| | | | | | | | | | | | | |
| Income tax expense from continuing operations | | 31.1 |
| | 46.0 |
| | 59.0 |
| | 17.7 |
| | 31.1 |
| | 46.0 |
|
| | | | | | | | | | | | | |
| Net income from continuing operations | | 57.4 |
| | 97.6 |
| | 130.0 |
| | 86.7 |
| | 57.4 |
| | 97.6 |
|
| | | | | | | | |
|
| |
|
| |
|
|
| Discontinued operations (Note 13) | | | | | | | |
| Loss from discontinued operations | | (56.3 | ) | | (1,338.7 | ) | | (47.5 | ) | |
| Discontinued operations (Note 14) | | | | | | | |
| Loss from discontinued operations before income tax | | | — |
| | (56.3 | ) | | (1,338.7 | ) |
| Income tax benefit from discontinued operations | | (15.9 | ) | | (468.4 | ) | | (23.9 | ) | | — |
| | (15.9 | ) | | (468.4 | ) |
| Net loss from discontinued operations | | (40.4 | ) | | (870.3 | ) | | (23.6 | ) | | — |
| | (40.4 | ) | | (870.3 | ) |
| | | | | | | | | | | | | |
| Net income / (loss) | | 17.0 |
| | (772.7 | ) | | 106.4 |
| | 86.7 |
| | 17.0 |
| | (772.7 | ) |
| | | | | | | | | | | | | |
| Dividends on preferred stock | | — |
| | 0.7 |
| | 0.9 |
| | — |
| | — |
| | 0.7 |
|
| | | | | | | | | | | | | |
| Income / (loss) attributable to common stock | | $ | 17.0 |
| | $ | (773.4 | ) | | $ | 105.5 |
| | $ | 86.7 |
| | $ | 17.0 |
| | $ | (773.4 | ) |
See Notes to Financial Statements.
| | THE DAYTON POWER AND LIGHT COMPANY | | STATEMENTS OF COMPREHENSIVE INCOME / (LOSS) | |
| Statements of Comprehensive Income / (Loss) | | Statements of Comprehensive Income / (Loss) |
| | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Net income / (loss) | | $ | 17.0 |
| | $ | (772.7 | ) | | $ | 106.4 |
| | $ | 86.7 |
| | $ | 17.0 |
| | $ | (772.7 | ) |
| Available-for-sale securities activity: | | | | | | | |
| Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of ($0.2), ($0.1) and $0.1 for each respective period | | 0.5 |
| | 0.2 |
| | (0.2 | ) | |
| 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 benefit of $0.0, $0.0 and $0.0 for each respective period | | (0.1 | ) | | — |
| | — |
| | — |
| | (0.1 | ) | | — |
|
| Net change in fair value of available-for-sale securities | | 0.4 |
| | 0.2 |
| | (0.2 | ) | |
| Net change in fair value of equity securities | | | — |
| | 0.4 |
| | 0.2 |
|
| Derivative activity: | | | | | | | | | | | | |
| Change in derivative fair value, net of income tax expense of ($7.2), ($8.7) and ($10.3) for each respective period | | 12.4 |
| | 16.1 |
| | 18.2 |
| |
| Reclassification to earnings, net of income tax benefit of $3.2, $16.4 and $5.6 for each respective period | | (6.2 | ) | | (30.0 | ) | | (9.8 | ) | |
| Change in derivative fair value, net of income tax benefit / (expense) of $0.1, ($7.2) and ($8.7) for each respective period | | | (0.1 | ) | | 12.4 |
| | 16.1 |
|
| Reclassification to earnings, net of income tax benefit of $0.4, $0.2 and $0.2 for each respective period | | | (0.7 | ) | | (0.7 | ) | | (0.8 | ) |
| Reclassification of earnings related to discontinued operations, net of income tax benefit of $0.0, $3.0 and $16.2 for each respective period | | | — |
| | (5.5 | ) | | (29.2 | ) |
| Net change in fair value of derivatives | | 6.2 |
| | (13.9 | ) | | 8.4 |
| | (0.8 | ) | | 6.2 |
| | (13.9 | ) |
| Pension and postretirement activity: | | | | | | | | | | | | |
| Prior service cost for the period, net of income tax benefit of $1.0, $0.0 and $0.0 for each respective period | | (1.9 | ) | | (0.1 | ) | | — |
| |
| Net gain / (loss) for the period, net of income tax benefit / (expense) of $0.4, $1.1 and ($1.0) for each respective period | | (0.8 | ) | | (5.9 | ) | | 1.7 |
| |
| Reclassification to earnings, net of income tax expense of ($2.3), ($1.8) and ($1.9) for each respective period | | 4.5 |
| | 5.9 |
| | 3.7 |
| |
| Prior service cost for the period, net of income tax benefit of $0.6, $1.0 and $0.0 for each respective period | | | (2.2 | ) | | (1.9 | ) | | (0.1 | ) |
| Net gain / (loss) for the period, net of income tax benefit / (expense) of ($0.4), $0.4 and $1.1 for each respective period | | | 1.7 |
| | (0.8 | ) | | (5.9 | ) |
| Reclassification to earnings, net of income tax expense of ($1.0), ($2.3) and ($1.8) for each respective period | | | 3.3 |
| | 4.5 |
| | 5.9 |
|
| Net change in unfunded pension and postretirement obligations | | 1.8 |
| | (0.1 | ) | | 5.4 |
| | 2.8 |
| | 1.8 |
| | (0.1 | ) |
| | | | | | | | | | | | | |
| Other comprehensive income / (loss) | | 8.4 |
| | (13.8 | ) | | 13.6 |
| | 2.0 |
| | 8.4 |
| | (13.8 | ) |
| | | | | | | | | | | | | |
| Net comprehensive income / (loss) | | $ | 25.4 |
| | $ | (786.5 | ) | | $ | 120.0 |
| | $ | 88.7 |
| | $ | 25.4 |
| | $ | (786.5 | ) |
See Notes to Financial Statements.
| | THE DAYTON POWER AND LIGHT COMPANY | | BALANCE SHEETS | |
| Balance Sheets | | Balance Sheets |
| $ in millions | | December 31, 2017 | | December 31, 2016 | | December 31, 2018 | | December 31, 2017 |
| ASSETS | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 5.2 |
| | $ | 1.6 |
| | $ | 45.0 |
| | $ | 5.2 |
|
| Restricted cash | | 0.4 |
| | — |
| | 21.2 |
| | 0.4 |
|
| Accounts receivable, net (Note 2) | | 70.8 |
| | 99.8 |
| | 90.4 |
| | 70.8 |
|
| Inventories (Note 2) | | 7.3 |
| | 9.3 |
| | 7.7 |
| | 7.3 |
|
| Taxes applicable to subsequent years | | 71.1 |
| | 67.9 |
| | 72.4 |
| | 71.1 |
|
| Regulatory assets, current (Note 3) | | 23.9 |
| | 0.1 |
| | 41.1 |
| | 23.9 |
|
| Taxes receivable | | | 19.6 |
| | 6.5 |
|
| Other prepayments and current assets | | 14.6 |
| | 9.5 |
| | 13.3 |
| | 14.6 |
|
| Assets held-for-sale - current (Note 13) | | — |
| | 324.6 |
| |
| Total current assets | | 193.3 |
| | 512.8 |
| | 310.7 |
| | 199.8 |
|
| | | | | | | | | |
| Property, plant and equipment: | | | | | | | | |
| Property, plant and equipment | | 2,247.2 |
| | 2,213.5 |
| | 2,274.4 |
| | 2,247.2 |
|
| Less: Accumulated depreciation and amortization | | (987.3 | ) | | (968.9 | ) | | (988.0 | ) | | (987.3 | ) |
| | | 1,259.9 |
| | 1,244.6 |
| | 1,286.4 |
| | 1,259.9 |
|
| Construction work in process | | 41.5 |
| | 39.3 |
| | 31.7 |
| | 41.5 |
|
| Total net property, plant and equipment | | 1,301.4 |
| | 1,283.9 |
| | 1,318.1 |
| | 1,301.4 |
|
| Other non-current assets: | | | | | | | | |
| Regulatory assets, non-current (Note 3) | | 163.2 |
| | 203.9 |
| | 152.6 |
| | 163.2 |
|
| Intangible assets, net of amortization | | 18.8 |
| | 22.1 |
| | 17.2 |
| | 18.8 |
|
| Other deferred assets | | 12.7 |
| | 12.4 |
| | 21.0 |
| | 12.7 |
|
| Total other non-current assets | | 194.7 |
| | 238.4 |
| | 190.8 |
| | 194.7 |
|
| Total Assets | | $ | 1,689.4 |
| | $ | 2,035.1 |
| | $ | 1,819.6 |
| | $ | 1,695.9 |
|
| | | | | | | | | |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Current portion - long-term debt (Note 7) | | $ | 4.6 |
| | $ | 4.6 |
| | $ | 4.6 |
| | $ | 4.6 |
|
| Short-term debt | | 10.0 |
| | 5.0 |
| | — |
| | 10.0 |
|
| Accounts payable | | 46.6 |
| | 55.7 |
| | 55.8 |
| | 46.6 |
|
| Accrued taxes | | 70.1 |
| | 72.2 |
| | 75.7 |
| | 76.6 |
|
| Accrued interest | | 0.8 |
| | 2.1 |
| | 0.4 |
| | 0.8 |
|
| Customer security deposits | | 21.8 |
| | 15.2 |
| | 21.3 |
| | 21.8 |
|
| Regulatory liabilities, current (Note 3) | | 14.8 |
| | 33.7 |
| | 34.9 |
| | 14.8 |
|
| Other current liabilities | | 12.9 |
| | 15.2 |
| | 17.5 |
| | 12.9 |
|
| Liabilities held-for-sale - current (Note 13) | | — |
| | 157.7 |
| |
| Total current liabilities | | 181.6 |
| | 361.4 |
| | 210.2 |
| | 188.1 |
|
| | | | | | | | | |
| Non-current liabilities: | | | | | | | | |
| Long-term debt (Note 7) | | 642.0 |
| | 731.5 |
| | 581.5 |
| | 642.0 |
|
| Deferred taxes (Note 8) | | 131.0 |
| | 266.9 |
| | 131.7 |
| | 131.0 |
|
| Taxes payable | | 75.8 |
| | 72.8 |
| | 77.1 |
| | 75.8 |
|
| Regulatory liabilities, non-current (Note 3) | | 221.2 |
| | 130.4 |
| | 278.3 |
| | 221.2 |
|
| Pension, retiree and other benefits (Note 9) | | 91.1 |
| | 93.4 |
| | 83.2 |
| | 91.1 |
|
| Unamortized investment tax credit | | 0.9 |
| | 1.1 |
| |
| Asset retirement obligations | | 8.0 |
| | 8.2 |
| | 4.7 |
| | 8.0 |
|
| Other deferred credits | | 7.1 |
| | 7.1 |
| | 7.6 |
| | 8.0 |
|
| Total non-current liabilities | | 1,177.1 |
| | 1,311.4 |
| | 1,164.1 |
| | 1,177.1 |
|
| | | | | | | | | |
| Commitments and contingencies (Note 11) | |
| |
| |
| |
|
| | | | | | | | | |
| Common shareholder's equity: | | | | | | | | |
| Common stock, par value of $0.01 per share | | 0.4 |
| | 0.4 |
| | 0.4 |
| | 0.4 |
|
| 250,000,000 shares authorized, 41,172,173 shares issued and outstanding | | | | | |
| 50,000,000 shares authorized, 41,172,173 shares issued and outstanding | | | | | |
| Other paid-in capital | | 685.8 |
| | 810.7 |
| | 711.8 |
| | 685.8 |
|
| Accumulated other comprehensive loss | | (36.2 | ) | | (42.5 | ) | | (35.3 | ) | | (36.2 | ) |
| Accumulated deficit | | (319.3 | ) | | (406.3 | ) | | (231.6 | ) | | (319.3 | ) |
| Total common shareholder's equity | | 330.7 |
| | 362.3 |
| | 445.3 |
| | 330.7 |
|
| | | | | | | | | |
| Total Liabilities and Shareholder's Equity | | $ | 1,689.4 |
| | $ | 2,035.1 |
| | $ | 1,819.6 |
| | $ | 1,695.9 |
|
See Notes to Financial Statements.
| | THE DAYTON POWER AND LIGHT COMPANY | | STATEMENTS OF CASH FLOWS | |
| Statements of Cash Flows | | Statements of Cash Flows |
| | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities: | | | | | | | | | | | | |
| Net income / (loss) | | $ | 17.0 |
| | $ | (772.7 | ) | | $ | 106.4 |
| | $ | 86.7 |
| | $ | 17.0 |
| | $ | (772.7 | ) |
| Adjustments to reconcile Net income (loss) to Net cash from operating activities | | | | | | | |
| Adjustments to reconcile Net income / (loss) to Net cash from operating activities | | | | | | | |
| Depreciation and amortization | | 87.2 |
| | 120.3 |
| | 138.2 |
| | 74.5 |
| | 87.2 |
| | 120.3 |
|
| Amortization of deferred financing costs | | 1.1 |
| | 2.9 |
| | 2.9 |
| | 3.1 |
| | 1.1 |
| | 2.9 |
|
| Unrealized loss (gain) on derivatives | | (1.0 | ) | | (4.2 | ) | | 5.7 |
| | — |
| | (1.0 | ) | | (4.2 | ) |
| Deferred income taxes | | 8.1 |
| | (477.5 | ) | | (19.2 | ) | | 16.3 |
| | 8.1 |
| | (477.5 | ) |
| Charge for early redemption of debt | | 1.1 |
| | 0.5 |
| | 4.8 |
| | 0.6 |
| | 1.1 |
| | 0.5 |
|
| Fixed-asset impairment | | 66.3 |
| | 1,353.5 |
| | — |
| | — |
| | 66.3 |
| | 1,353.5 |
|
| Loss on disposal of business | | | 12.4 |
| | — |
| | — |
|
| Loss / (Gain) on asset disposal | | 15.7 |
| | — |
| | 0.4 |
| | 0.2 |
| | 15.7 |
| | (0.1 | ) |
| Changes in certain assets and liabilities: | | | | | | | | | | | | |
| Accounts receivable | | 13.3 |
| | (9.7 | ) | | 28.7 |
| | 13.5 |
| | 14.6 |
| | (8.3 | ) |
| Inventories | | 10.3 |
| | 32.2 |
| | (9.1 | ) | | (0.3 | ) | | 10.3 |
| | 32.2 |
|
| Prepaid taxes | | — |
| | 2.7 |
| | (1.3 | ) | | — |
| | — |
| | 2.7 |
|
| Taxes applicable to subsequent years | | 6.4 |
| | — |
| | (3.7 | ) | | (1.3 | ) | | 6.4 |
| | — |
|
| Deferred regulatory costs, net | | (23.7 | ) | | 4.1 |
| | 21.8 |
| | (9.2 | ) | | (23.7 | ) | | 4.1 |
|
| Accounts payable | | (48.0 | ) | | 16.0 |
| | (5.8 | ) | | 3.8 |
| | (48.7 | ) | | 14.6 |
|
| Accrued taxes payable | | (17.5 | ) | | (10.5 | ) | | 7.3 |
| |
| Accrued taxes payable / receivable | | | (12.7 | ) | | (17.5 | ) | | (10.5 | ) |
| Accrued interest payable | | (1.3 | ) | | (2.0 | ) | | (5.7 | ) | | (0.4 | ) | | (1.3 | ) | | (2.0 | ) |
| Pension, retiree and other benefits | | 4.3 |
| | 8.6 |
| | (0.7 | ) | | (2.4 | ) | | 4.8 |
| | 3.0 |
|
| Unamortized investment tax credit | | (1.7 | ) | | (2.3 | ) | | (2.4 | ) | |
| Other | | (2.2 | ) | | 2.9 |
| | (11.6 | ) | | 11.0 |
| | (5.0 | ) | | (21.3 | ) |
| Net cash provided by operating activities | | 135.4 |
| | 264.8 |
| | 256.7 |
| | 195.8 |
| | 135.4 |
| | 237.2 |
|
| Cash flows from investing activities: | | | | | | | | | | | | |
| Capital expenditures | | (101.7 | ) | | (128.3 | ) | | (127.0 | ) | | (93.1 | ) | | (101.7 | ) | | (128.3 | ) |
| Decrease / (increase) in restricted cash | | 26.6 |
| | (11.9 | ) | | (0.3 | ) | |
| Purchase of renewable energy credits | | (0.6 | ) | | (0.4 | ) | | (0.8 | ) | |
| Payments on disposal of business | | | (14.5 | ) | | — |
| | — |
|
| Proceeds from sale of property | | | 10.6 |
| | — |
| | 0.2 |
|
| Insurance proceeds | | 12.5 |
| | 6.1 |
| | 5.2 |
| | 0.4 |
| | 12.5 |
| | 6.1 |
|
| Other investing activities, net | | 0.3 |
| | 1.1 |
| | 0.4 |
| | (0.3 | ) | | (0.3 | ) | | 0.4 |
|
| Net cash used in investing activities | | (62.9 | ) | | (133.4 | ) | | (122.5 | ) | | (96.9 | ) | | (89.5 | ) | | (121.6 | ) |
| Cash flows from financing activities | | | | | | | | | | | | |
| Dividends and returns of capital paid to parent | | (39.0 | ) | | (70.0 | ) | | (50.0 | ) | | (43.8 | ) | | (39.0 | ) | | (70.0 | ) |
| Dividends paid on preferred stock | | — |
| | (0.7 | ) | | (0.9 | ) | | — |
| | — |
| | (0.7 | ) |
| Retirement of long-term debt | | (104.5 | ) | | (445.3 | ) | | (314.4 | ) | | (64.5 | ) | | (104.5 | ) | | (445.3 | ) |
| Capital contribution from parent | | 70.0 |
| | — |
| | — |
| | 80.0 |
| | 70.0 |
| | — |
|
| Issuance of long-term debt | | — |
| | 442.8 |
| | 200.0 |
| | — |
| | — |
| | 442.8 |
|
| Deferred financing costs | | — |
| | (8.5 | ) | | (3.9 | ) | | — |
| | — |
| | (8.5 | ) |
| Redemption on preferred stock | | — |
| | (23.5 | ) | | — |
| | — |
| | — |
| | (23.5 | ) |
| Borrowings from revolving credit facilities | | 40.0 |
| | — |
| | 50.0 |
| | 30.0 |
| | 40.0 |
| | — |
|
| Repayment of borrowings from revolving credit facilities | | (30.0 | ) | | — |
| | (50.0 | ) | | (40.0 | ) | | (30.0 | ) | | — |
|
| Borrowings from related party | | 30.0 |
| | 10.0 |
| | 35.0 |
| | — |
| | 30.0 |
| | 10.0 |
|
| Repayment of borrowings from related party | | (35.0 | ) | | (40.0 | ) | | — |
| | — |
| | (35.0 | ) | | (40.0 | ) |
| Other financing activities, net | | (0.4 | ) | | — |
| | — |
| | — |
| | (0.4 | ) | | — |
|
| Net cash used in financing activities | | (68.9 | ) | | (135.2 | ) | | (134.2 | ) | | (38.3 | ) | | (68.9 | ) | | (135.2 | ) |
| Cash and cash equivalents: | | | | | | | |
| Net increase / (decrease) in cash | | 3.6 |
| | (3.8 | ) | | — |
| |
| Increase in cash and restricted cash of discontinued operations and held-for-sale businesses | | | — |
| | 27.0 |
| | 15.8 |
|
| Cash, cash equivalents, and restricted cash: | | | | | | | . |
| Net increase / (decrease) in cash, cash equivalents and restricted cash | | | 60.6 |
| | 4.0 |
| | (3.8 | ) |
| Balance at beginning of year | | 1.6 |
| | 5.4 |
| | 5.4 |
| | 5.6 |
| | 1.6 |
| | 5.4 |
|
| Cash and cash equivalents at end of year | | $ | 5.2 |
| | $ | 1.6 |
| | $ | 5.4 |
| |
| Cash, cash equivalents, and restricted cash at end of year | | | $ | 66.2 |
| | $ | 5.6 |
| | $ | 1.6 |
|
| Supplemental cash flow information: | | | | | | | | | | | | |
| Interest paid, net of amounts capitalized | | $ | 28.4 |
| | $ | 21.4 |
| | $ | 27.5 |
| | $ | 22.9 |
| | $ | 28.4 |
| | $ | 21.4 |
|
| Income taxes (refunded) / paid, net | | $ | 28.1 |
| | $ | 0.3 |
| | $ | 0.8 |
| |
| Income taxes paid, net | | | $ | 13.1 |
| | $ | 28.1 |
| | $ | 0.3 |
|
| Non-cash financing and investing activities: | | | | | | | | | | | | |
| Accruals for capital expenditures | | $ | 19.7 |
| | $ | 14.8 |
| | $ | 16.9 |
| | $ | 10.8 |
| | $ | 19.7 |
| | $ | 14.8 |
|
| Equity contribution to settle liability | | $ | — |
| | $ | 7.5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7.5 |
|
| Distribution of generation assets to subsidiary of parent | | (86.2 | ) | | $ | — |
| | $ | — |
| | $ | (10.0 | ) | | $ | (86.2 | ) | | $ | — |
|
See Notes to Financial Statements.
| | THE DAYTON POWER AND LIGHT COMPANY | | STATEMENTS OF SHAREHOLDER'S EQUITY | |
| Statements of Shareholder's Equity | | Statements of Shareholder's Equity |
| | | Common Stock (a) | | | | | | | | | | Common Stock (a) | | | | | | | | |
| $ in millions | | Outstanding Shares | | Amount | | Other Paid-in Capital | | Accumulated Other Comprehensive Income / (Loss) | | Retained Earnings / Accumulated Deficit | | Total | | Outstanding Shares | | Amount | | Other Paid-in Capital | | Accumulated Other Comprehensive Income / (Loss) | | Retained Earnings / Accumulated Deficit | | Total |
| Year ended December 31, 2016 | | | | | | | | | | | | | |
| Beginning balance | | 41,172,173 |
| | $ | 0.4 |
| | $ | 803.5 |
| | $ | (42.3 | ) | | $ | 381.8 |
| | $ | 1,143.4 |
| | 41,172,173 |
| | $ | 0.4 |
| | $ | 803.7 |
| | $ | (28.7 | ) | | $ | 437.3 |
| | $ | 1,212.7 |
|
| Year ended December 31, 2015 | | | | | | | | | | | | | |
| Net comprehensive income | | | | | | | | 13.6 |
| | 106.4 |
| | 120.0 |
| |
| Common stock dividends | | | | | | | | | | (50.0 | ) | | (50.0 | ) | |
| Preferred stock dividends | | | | | | | | | | (0.9 | ) | | (0.9 | ) | |
| Other | | | | | | 0.2 |
| | | |
|
| | 0.2 |
| |
| Ending balance | | 41,172,173 |
| | 0.4 |
| | 803.7 |
| | (28.7 | ) | | 437.3 |
| | 1,212.7 |
| |
| Year ended December 31, 2016 | | | | | | | | | | | | | |
| Net comprehensive loss | | | | | | | | (13.8 | ) | | (772.7 | ) | | (786.5 | ) | | | | | | | | (13.8 | ) | | (772.7 | ) | | (786.5 | ) |
| Common stock dividends | | | | | | | | | | (70.0 | ) | | (70.0 | ) | |
| Common stock dividends and returns of capital | | | | | | | | | | | (70.0 | ) | | (70.0 | ) |
| Preferred stock dividends | | | | | | | | | | (0.7 | ) | | (0.7 | ) | | | | | | | | | | (0.7 | ) | | (0.7 | ) |
| Other | | | | | | 7.0 |
| | | | (0.2 | ) | | 6.8 |
| | | | | | 7.0 |
| | | | (0.2 | ) | | 6.8 |
|
| Ending balance | | 41,172,173 |
| | 0.4 |
| | 810.7 |
| | (42.5 | ) | | (406.3 | ) | | 362.3 |
| | 41,172,173 |
| | 0.4 |
| | 810.7 |
| | (42.5 | ) | | (406.3 | ) | | 362.3 |
|
| Year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | | | | | | |
| Net comprehensive income | | | | | | | | 8.4 |
| | 17.0 |
| | 25.4 |
| | | | | | | | 8.4 |
| | 17.0 |
| | 25.4 |
|
| Common stock dividends | | | | | | (39.0 | ) | | | |
|
| | (39.0 | ) | |
| Common stock dividends and returns of capital | | | | | | | (39.0 | ) | | | |
|
| | (39.0 | ) |
| Transfer of generation assets to subsidiary of parent | | | | | | (86.2 | ) | | (2.1 | ) | | | | (88.3 | ) | | | | | | (86.2 | ) | | (2.1 | ) | |
|
| | (88.3 | ) |
| Capital contribution from parent | | | | | | 70.0 |
| | | | | | 70.0 |
| | | | | | 70.0 |
| | | | | | 70.0 |
|
Other (b) | | | | | | (69.7 | ) | | | | 70.0 |
| | 0.3 |
| | | | | | (69.7 | ) | | | | 70.0 |
| | 0.3 |
|
| Ending balance | | 41,172,173 |
| | $ | 0.4 |
| | $ | 685.8 |
| | $ | (36.2 | ) | | $ | (319.3 | ) | | $ | 330.7 |
| | 41,172,173 |
| | 0.4 |
| | 685.8 |
| | (36.2 | ) | | (319.3 | ) | | 330.7 |
|
| Year ended December 31, 2018 | | | | | | | | | | | | | |
| Net comprehensive income | | | | | | | | | 2.0 |
| | 86.7 |
| | 88.7 |
|
| Common stock dividends and returns of capital | | | | | | | (43.8 | ) | | | |
|
| | (43.8 | ) |
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, 250,000,00050,000,000 shares authorized. |
| |
| (b) | In the current period,2017, we have reclassified the presentation of the December 2016 dividend payment of $70.0 million whichmillion. This was originally recorded as a charge to Accumulated deficit and is now presentedbut 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. |
See Notes to Financial Statements.
The Dayton Power and Light Company
Notes to Financial Statements
For the years ended December 31, 2018, 2017 2016 and 20152016
Note 1 – Overview and Summary of Significant Accounting Policies
Description of Business
DP&Lis 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 521,000525,000 customers located in West Central Ohio. DP&L is required to procure and provideprovides 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 100%all of the generation for its SSO customers through a competitive bid process. Through September 30, 2017, DP&L owned undivided interests in fivemultiple 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. 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.
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.costs or overcollections of riders.
DP&L employed 660647 people at January 31, 2018.2019. Approximately 53%58% of all employees are under a collective bargaining agreement. The current agreement, after initially being extended, expired on January 31, 2018. Under national labor law, all the terms and conditions of the expired agreement continue indefinitely, with a few exceptions. Notably, the union has the right to strike and DP&L has the right to lock out employees. We are continuing to negotiate with the union to enter into a new collective bargaining agreement. Currently, we are unable to predict the eventual outcome of these negotiations and have contingency plans to continue our operations. If we are not able to reach an agreement on terms favorable to us or to effectively implement our plans in the event that agreement is not reached, our results of operations, financial position and cash flows could be adversely impacted.
Financial Statement Presentation
DP&L does not have any subsidiaries.
Through June 2018, DP&L hashad undivided ownership interests in numerous transmission facilities. These undivided interests in jointly-owned facilities arewere accounted for on a pro rata basis in the Financial Statements. In the fourth quarter of 2017,June 2018, DP&L entered into an agreementclosed on a transmission asset transaction with two other Ohio utilitiesDuke 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 co-ownership relationship they have had with respect to certain transmission facilities (transmission lines and substations) located in Ohio.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. In 2017, we have reclassified the presentation of the December 2016 dividend payment of $70.0 million which was originally recorded as a charge to Accumulated deficit and is now presented as a charge to Other paid-in capital. This reclassification was to prospectively correct an immaterial error.
The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the
revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidenceRevenue is recognized upon transfer of an arrangement exists, the productscontrol of promised goods or services have been provided to customers in an amount that reflects the customer, the sales price is fixedconsideration to which we expect to be entitled in exchange for those goods or determinable, and collection is reasonably assured.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.regulators AFUDC and capitalized interest was $2.0$0.5 million, $2.7$1.5 million and $2.0 million for the years ended December 31, 2018, 2017 2016 and 2015,2016, 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 primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s 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 and 2.5% in 2015.2016. Depreciation expense was $69.6$68.2 million, $64.3$69.6 million and $64.3 million for the years ended December 31, 2018, 2017 and 2016, and 2015, 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.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.years AmortizationAmortization expense was $6.3 million, $5.7 million $6.7 million and $7.2$6.7 million for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. The estimated amortization expense of this internal-use software over the next five years is $10.7$11.1 million ($5.1 million in 2018, $3.13.5 million in 2019, $1.6$2.4 million in 2020, $0.6$2.2 million in 2021, and $0.3$1.8 million in 2022)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.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.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.approach See Note 8 – Income Taxes for additional information.
Financial Instruments
We classify ourOur Master Trust investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-saleare classified as equity investments. These equity securities are carried at fair value and unrealized gains and losses on thosethese securities netare recorded in Other income. As these financial instruments are held to be used for the benefit of deferred income taxes,employees participating in employee benefit plans and are presented as a separate component of shareholder's equity. Other-than-temporary declines in valuenot used for general operating purposes, they are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.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 livedlong-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 1314 – Generation Separation for further information.
Discontinued Operations
Discontinued operations reporting occurs only when the disposal of a business or a group of businessesassets 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 1314 – Generation Separation for further information.
Generation Separation
With the transfer of DP&L's generation assets to an affiliate (see Note 1314 – 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 2016 and 20152016 and in the footnotesnotes to the financial statements. The assets and liabilities related to the discontinued operations have been reclassified to held-for-sale in the balance sheet as of December 31, 2016.
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 and 2015 were $51.7 million, $49.4 million $50.9 million and $49.9$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 relatesincludes 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:
|
| | | | | | | | |
| $ in millions | | December 31, 2018 | | December 31, 2017 |
| Cash and cash equivalents | | $ | 45.0 |
| | $ | 5.2 |
|
| Restricted cash | | 21.2 |
| | 0.4 |
|
| Cash, Cash Equivalents, and Restricted Cash, End of Period | | $ | 66.2 |
| | $ | 5.6 |
|
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.
We use forward contractsinterest rate hedges to reducemanage the interest rate risk of our exposure to changes in interest rates.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 and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. DP&L is responsible for claimclaims 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 MVIC and third-party providers. We recorded these additional insurance and claims costsproviders of approximately $4.4$4.3 million and $3.9$4.4 million at December 31, 20172018 and 2016,2017, 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 in the funded status,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.
Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of FASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.
See Note 9 – Benefit Plans for more information.
Related Party Transactions
In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES. See Note 12 – Related Party Transactions for additional information on Related Party Transactions.
New accounting pronouncements adopted in 2018
The following table provides a brief description of recentrecently adopted accounting pronouncements that couldhad 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:statements.
|
| | | |
| Accounting Standard | Description | Date of Adoption | Effect on the financial statements upon adoption |
| New Accounting Standards Adopted |
2016-09,2018-15, 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. | October 1, 2018 | 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. | Early adoption elected, January 1, 2018 | Impact limited to changes in financial statement disclosures. |
2017-07, Compensation - Stock CompensationRetirement Benefits (Topic 718)715): ImprovementsImproving 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. | January 1, 2018 | For the years ended December 31, 2017 and 2016 we reclassified non-service pension costs from Operating expenses to Employee Share-Based Payment AccountingOther 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) | TheThis standard simplifiesrequires that a statement of cash flows explain the following aspectschange during the period in the total of accounting for share-based payment awards: accounting for income taxes, classification of excess tax benefitscash, 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, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes.flows.
Transition method: The recording of excess tax benefits and tax deficiencies arising from vesting or settlement will be applied prospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized will be adopted on a modified retrospective basis with a cumulative adjustment to the opening balance sheet.retrospective. | January 1, 2017.2018 | 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 recognitionstandard significantly revises an entity’s accounting related to (1) classification and measurement of excess tax benefitsinvestments in our provisionequity securities and (2) the presentation of certain fair value changes for income taxes infinancial 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. | January 1, 2018 | 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) | See discussion of the period whenASU below. | January 1, 2018 | See impact upon adoption of the awards vest or are settled, rather than in paid-in-capitalstandard below. |
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 period when the excess tax benefits are realized.financial statements upon adoption |
New Accounting Standards Issued Butbut 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. | January 1, 2019. Early adoption is permitted. | We are currently evaluating thedo not expect any impact on our financial statements upon adoption of adopting the standard on our financial statements.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.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. | January 1, 2019. Early adoption is permitted. | We are currently evaluating the impact of adopting the standard on our financial statements. |
2017-08, Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities | This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date.
Transition method: modified retrospective. | January 1, 2019. Early adoption is permitted. | We are currently evaluating the impact of adopting the standard on our financial statements. |
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 cost associated with defined benefit plans and updates the guidance so that only the service cost component will be eligible for capitalization. | January 1, 2018. | We expect the adoption of this standard to result in a reclassification of non-service pension costs from Operating expenses to Other expense of $7.2 million and $7.8 million in 2017 and 2016, respectively. |
2016-18, Statement of Cash Flows (Topic 320): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) | This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.
Transition method: retrospective. | January 1, 2018 | We expect the adoption of this standard to result in a reclassification from "Net cash used in investing activities" to "Net increase / (decrease) in cash" of $26.6 million and ($11.9) million in 2017 and 2016, respectively. |
|
| | | |
Accounting Standard | Description | Date of Adoption | Effect on the financial statements upon adoption |
2018-19, 2016-13, Financial Instruments-CreditInstruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments | The standard updates the impairment model for financial assets measured at amortized costcost. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to an expected lossuse a new forward-looking "expected loss" model rather than an incurred loss model. It also allowsthat generally will result in the earlier recognition of allowance for the presentation oflosses. For available-for-sale debt securities with unrealized losses, entities will measure credit losses on available-for-sale debt securitiesas it is done today, except that the losses will be recognized as an allowance rather than a write down.reduction in the amortized cost of the securities.
Transition method: various. | January 1, 2020. Early adoption is permitted only as of January 1, 2019. | We are currently evaluating the impact of adopting the standard on our financial statements. |
2016-02, 2018-01, 2018-10, 2018-11, 2018-20
Leases (Topic 842) | See discussion of the ASU below. | January 1, 2019. Early adoption is permitted. | We are currently evaluating the impact of adoptingwill adopt the standard on our financial statements. |
2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, Revenue from Contracts with Customers (Topic 606) | See discussion of the ASUs below. | January 1, 2018. | We will adopt the standards on January 1, 2018;2019; see below for the evaluation of the impact of its adoption on theour financial statements. |
ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transferAdoption of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard replaces most existing revenue recognition guidance in GAAP.
The standard requires retrospective application and allows either a full retrospective adoption in which all of the periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application.
In 2016, we established a cross-functional implementation team and are in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.
We are assessing the standard on a contract-by-contract basis applying the interpretations reached during 2017 on key issues. This includes the application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, we have been working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sale and purchases. Through this assessment to date, we have not identified any situations where revenue recognized under FASC 606 could differ from that recognized under FASC 605 or where the presentation of sales to and purchases from the spot markets will change. Given the limited impact, we expect to use the modified retrospective approach.
We are continuing to work with various non-authoritative industry groups and continue to monitor the FASB and Transition Resource Group activity as we finalize our accounting policy on these and other industry-specific interpretive issues.
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,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 requiresmust be adopted using a modified retrospective adoption at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).approach. The FASB proposed amending the standard to give another option for transition. The proposedhas provided an optional transition method, would allowwhich we have elected, that allows entities to notcontinue to apply the new lease standardguidance in FASC 840 Leases to the comparative periods presented in their financial statements in the year of adoption. Under the proposedthis transition method, the entity wouldwe will apply the transition provisions starting on January 1, 2019 (i.e., the effective date). At transition, lessees and lessors are permitted to make an election2019.
We have elected to apply a package of practical expedients that allow themlessees 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. Furthermore, entities areWe have also permittedelected to makeapply an electionoptional transition practical expedient for land easements that allows an entity to use hindsight when determining lease term and entities can elect to use hindsight when assessing
continue applying its current accounting policy for all land easements that exist before the impairment of right-of-use assets.standard’s effective date that were not previously accounted for under FASC 840.
We have established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use assetassets and related liability.liabilities. Additionally, the implementation team has been working on the identification and selectionconfiguration of a lease accounting systemtool that wouldwill support the implementation and the subsequent accounting. The implementation team is in the process of evaluatinghas also evaluated changes to our business processes, systems and controls to support recognition and disclosure under the new standard.
As we have preliminarily concluded that at transition we would be using the package of practical expedients, the main impact expected as of the effective date is the recognition of the right to use asset and the related liability in the financial statements for all those contracts that contain a lease and for which we are the lessee. However, income statement presentation and the expense recognition pattern is not expected to change.
Under FASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of today'sthe 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 that dependsuch as margin on the usesale of the asset (e.g. Mwh produced by a facility).energy. Therefore, the lease receivable could be lowersignificantly 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 selling gain/loss at lease commencement. We are assessing situations for which this guidance would apply.
The adoption of FASC 842 did not have a material impact on our financial statements.
Note 2 – Supplemental Financial Information
| | | | | December 31, | | December 31, |
| $ in millions | | 2017 | | 2016 | | 2018 | | 2017 |
| Accounts receivable, net | | | | | | | | |
| Customer receivables | | | $ | 53.3 |
| | $ | 44.2 |
|
| Unbilled revenue | | $ | 18.0 |
| | $ | 43.0 |
| | 16.8 |
| | 18.0 |
|
| Customer receivables | | 44.2 |
| | 45.9 |
| |
| Amounts due from partners in jointly-owned stations | | 5.0 |
| | 4.0 |
| | — |
| | 5.0 |
|
Due from PJM transmission enhancement settlement (a) | | | 16.5 |
| | — |
|
| Due from affiliates | | | 2.3 |
| | 0.6 |
|
| Other | | 4.7 |
| | 8.1 |
| | 2.4 |
| | 4.1 |
|
| Provisions for uncollectible accounts | | (1.1 | ) | | (1.2 | ) | | (0.9 | ) | | (1.1 | ) |
| Total accounts receivable, net | | $ | 70.8 |
| | $ | 99.8 |
| | $ | 90.4 |
| | $ | 70.8 |
|
| | | | | | | | | |
| Inventories, at average cost | | | | | | | | |
| Plant materials and supplies | | $ | 6.9 |
| | $ | 6.9 |
| |
| Materials and supplies | | | $ | 7.1 |
| | $ | 6.9 |
|
| Other | | 0.4 |
| | 2.4 |
| | 0.6 |
| | 0.4 |
|
| Total inventories, at average cost | | $ | 7.3 |
| | $ | 9.3 |
| | $ | 7.7 |
| | $ | 7.3 |
|
(a) - See Note 3 – Regulatory Matters for more information.
Accumulated Other Comprehensive Income / (Loss)
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2018, 2017 2016 and 20152016 are as follows:
| | | Details about Accumulated Other Comprehensive Income / (Loss) Components | | Affected line item in the Statements of Operations | | Years ended December 31, | | Affected line item in the Statements of Operations | | Years ended December 31, |
| $ in millions | | | | 2017 | | 2016 | | 2015 | | | | 2018 | | 2017 | | 2016 |
| Gains and losses on Available-for-sale securities activity (Note 5): | | | | | | | |
| Gains and losses on equity securities activity (Note 5): | | Gains and losses on equity securities activity (Note 5): | | | | | | |
| | | Other deductions | | $ | (0.1 | ) | | $ | — |
| | $ | — |
| | Other deductions | | $ | — |
| | $ | (0.1 | ) | | $ | — |
|
| | | Income tax expense from continuing operations | | — |
| | — |
| | — |
| | Income tax expense | | — |
| | — |
| | — |
|
| | | Net of income taxes | | (0.1 | ) | | — |
| | — |
| | Net of income taxes | | — |
| | (0.1 | ) | | — |
|
| | | | | | | | | | | | | |
| Gains and losses on cash flow hedges (Note 6): | Gains and losses on cash flow hedges (Note 6): | | | | | | | Gains and losses on cash flow hedges (Note 6): | | | | | | |
| | | | Interest expense | | (1.1 | ) | | (0.9 | ) | | (1.0 | ) |
| | | | Income tax benefit | | 0.4 |
| | 0.2 |
| | 0.2 |
|
| | | Interest expense | | (0.9 | ) | | (1.0 | ) | | (1.1 | ) | | Net of income taxes | | (0.7 | ) | | (0.7 | ) | | (0.8 | ) |
| | | Income tax expense from continuing operations | | 0.2 |
| | 0.2 |
| | 0.2 |
| | | | | | |
| | | Loss from discontinued operations | | (8.5 | ) | | (45.4 | ) | | (14.3 | ) | | Loss from discontinued operations | | — |
| | (8.5 | ) | | (45.4 | ) |
| | | Income tax benefit from discontinued operations
| | 3.0 |
| | 16.2 |
| | 5.4 |
| | Income tax benefit from discontinued operations | | — |
| | 3.0 |
| | 16.2 |
|
| | | Net of income taxes | | (6.2 | ) | | (30.0 | ) | | (9.8 | ) | | Net of income taxes | | — |
| | (5.5 | ) | | (29.2 | ) |
| | | | | | | | | | | | | |
| Amortization of defined benefit pension items (Note 9): | Amortization of defined benefit pension items (Note 9): | | | | | | | Amortization of defined benefit pension items (Note 9): | | | | | | |
| | | Operation and maintenance | | 6.8 |
| | 7.7 |
| | 5.6 |
| | Other income | | 4.3 |
| | 6.8 |
| | 7.7 |
|
| | | Income tax expense from continuing operations | | (2.3 | ) | | (1.8 | ) | | (1.9 | ) | | Income tax expense | | (1.0 | ) | | (2.3 | ) | | (1.8 | ) |
| | | Net of income taxes | | 4.5 |
| | 5.9 |
| | 3.7 |
| | Net of income taxes | | 3.3 |
| | 4.5 |
| | 5.9 |
|
| | | | | | | | | | | | | |
| Total reclassifications for the period, net of income taxes | Total reclassifications for the period, net of income taxes | | $ | (1.8 | ) | | $ | (24.1 | ) | | $ | (6.1 | ) | 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, 20172018 and 20162017 are as follows:
| | | $ in millions | | Gains / (losses) on available-for-sale securities | | Gains / (losses) on cash flow hedges | | Change in unfunded pension obligation | | Total | | Gains / (losses) on equity securities | | Gains / (losses) on cash flow hedges | | Change in unfunded pension obligation | | Total |
| Balance at December 31, 2015 | | $ | 0.5 |
| | $ | 11.2 |
| | $ | (40.4 | ) | | $ | (28.7 | ) | |
| | | | | | | | | | |
| Other comprehensive income / (loss) before reclassifications | | 0.2 |
| | 16.1 |
| | (6.0 | ) | | 10.3 |
| |
| Amounts reclassified from accumulated other comprehensive income / (loss) | | — |
| | (30.0 | ) | | 5.9 |
| | (24.1 | ) | |
| Net current period other comprehensive income / (loss) | | 0.2 |
| | (13.9 | ) | | (0.1 | ) | | (13.8 | ) | |
| | | | | | | | | | |
| Balance at December 31, 2016 | | 0.7 |
| | (2.7 | ) | | (40.5 | ) | | (42.5 | ) | | $ | 0.7 |
| | $ | (2.7 | ) | | $ | (40.5 | ) | | $ | (42.5 | ) |
| | | | | | | | | | | | | | | | | |
| Other comprehensive income / (loss) before reclassifications | | 0.5 |
| | 12.4 |
| | (2.7 | ) | | 10.2 |
| | 0.5 |
| | 12.4 |
| | (2.7 | ) | | 10.2 |
|
| Amounts reclassified from accumulated other comprehensive income / (loss) | | (0.1 | ) | | (6.2 | ) | | 4.5 |
| | (1.8 | ) | | (0.1 | ) | | (6.2 | ) | | 4.5 |
| | (1.8 | ) |
| Net current period other comprehensive income | | 0.4 |
| | 6.2 |
| | 1.8 |
| | 8.4 |
| | 0.4 |
| | 6.2 |
| | 1.8 |
| | 8.4 |
|
| | | | | | | | | | | | | | | | | |
| Transfer of generation assets to subsidiary of parent | | — |
| | (2.1 | ) | | — |
| | (2.1 | ) | | — |
| | (2.1 | ) | | — |
| | (2.1 | ) |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2017 | | $ | 1.1 |
| | $ | 1.4 |
| | $ | (38.7 | ) | | $ | (36.2 | ) | | 1.1 |
| | 1.4 |
| | (38.7 | ) | | (36.2 | ) |
| | | | | | | | | | |
| Other comprehensive loss before reclassifications | | | — |
| | (0.1 | ) | | (0.5 | ) | | (0.6 | ) |
| Amounts reclassified from accumulated other comprehensive income / (loss) to earnings | | | — |
| | (0.7 | ) | | 3.3 |
| | 2.6 |
|
| Net current period other comprehensive income / (loss) | | | — |
| | (0.8 | ) | | 2.8 |
| | 2.0 |
|
| | | | | | | | | | |
Amounts reclassified from accumulated other comprehensive income to accumulated deficit (a) | | | (1.1 | ) | | — |
| | — |
| | (1.1 | ) |
| | | | | | | | | | |
| Balance at December 31, 2018 | | | $ | — |
| | $ | 0.6 |
| | $ | (35.9 | ) | | $ | (35.3 | ) |
| |
| (a) | 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 JanuaryDecember 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 a settlement inan amended stipulation to its 2017 ESP, case and filed an amended stipulation on March 13, 2017, which was subject to approval by the PUCO. A final decision was issued by the PUCO on October 20, 2017, modifying and adopting the amended stipulation and recommendation. The six-year 2017 ESP establishes DP&L's framework for providing retail service on a going forwardgoing-forward basis including rate structures, non-bypassable charges and other specific rate recovery true-up mechanisms. The signatory parties agreed to a six-year settlement that provides a framework for energy rates and defines componentsmechanisms 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;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 is to bewas established in a separatethe DP&L distribution rate case;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.
As partOn October 19, 2018 IGS, a retail electricity supplier, filed a Notice of Withdrawal from the normal review and approval process,amended settlement, citing a material modification by the PUCO‘s order approvingPUCO'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 settlementOrder to the Supreme Court of Ohio. That appeal is subject to rehearing requests. Several parties, including DP&L, applied for a rehearing. Those rehearing applications are still 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. AOn October 22, 2018, a stipulation was reached with the PUCO staff agreeing that DP&L did not exceed the SEET threshold for 2015, which was approved by the2016 or 2017. That stipulation is pending PUCO on September 6, 2017. On May 15, 2017, DP&L filed its application to demonstrate that it did not have significantly excessive earnings for calendar year 2016. That case is still pending.approval. In future years, the SEET could have a material effect on results of operations, financial condition and cash flows.
The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. We are not able at this time to predict the impact of this proceeding on our business, financial condition or results of operations.
Impact of tax reformTax 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 paymentspayments. 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 ifany 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&L’s rates are reducedwere 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, our cash flows could be adversely affected. It is too earlyresulting 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 whetherthe amount of excess deferred income taxes caused by the TCJA. DP&L is unable to predict the outcome of this proceedingnotice or the impact it may have a material impact 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&L’s business, financial conditiontransmission 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 results of operations.net income as all credits will be passed to DP&L’s customers through the TCRR, which began in November 2018.
Regulatory assetsAssets and liabilitiesLiabilities
In accordance with FASC 980, we have recognized total regulatory assets of $187.1$193.7 million and $204.0$187.1 million at December 31, 20172018 and 2016,2017, respectively, and total regulatory liabilities of $236.0$313.2 million and $164.1$236.0 million at December 31, 20172018 and 2016,2017, 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, | | Type of Recovery | | Amortization Through | | December 31, |
| $ in millions | | 2017 | | 2016 | | 2018 | | 2017 |
| Regulatory assets, current: | | | | | | | | | | | | | | | | |
| Undercollections to be collected through rate riders | | A/B | | 2018 | | $ | 23.9 |
| | $ | 0.1 |
| | A/B | | 2019 | | $ | 40.5 |
| | $ | 23.9 |
|
| Rate case expenses being recovered in base rates | | | B | | 2019 | | 0.6 |
| | — |
|
| Total regulatory assets, current | | 23.9 |
| | 0.1 |
| | 41.1 |
| | 23.9 |
|
| | | | | | |
| Regulatory assets, non-current: | | | | | | | | |
| Pension benefits | | B | | Ongoing | | 92.4 |
| | 97.6 |
| | B | | Ongoing | | 87.5 |
| | 92.4 |
|
| Deferred recoverable income taxes | | B/C | | Ongoing | | — |
| | 35.9 |
| |
| Unrecovered OVEC charges | | D | | Undetermined | | 27.8 |
| | 21.0 |
| | C | | Undetermined | | 28.7 |
| | 27.8 |
|
| Fuel costs | | B | | 2020 | | 9.3 |
| | 15.4 |
| | B | | 2020 | | 3.3 |
| | 9.3 |
|
| Regulatory compliance costs | | B | | 2020 | | 9.2 |
| | 12.4 |
| | B | | 2020 | | 6.1 |
| | 9.2 |
|
| Rate case costs | | B | | Undetermined | | 8.1 |
| | 6.3 |
| |
| Smart grid and AMI costs | | B | | Undetermined | | 7.3 |
| | 7.3 |
| | B | | Undetermined | | 8.5 |
| | 7.3 |
|
| Unamortized loss on reacquired debt | | B | | Various | | 7.0 |
| | 8.0 |
| | B | | Various | | 6.0 |
| | 7.0 |
|
| Deferred storm costs | | A | | Undetermined | | 2.1 |
| | — |
| | A | | Undetermined | | 4.7 |
| | 2.1 |
|
| Deferred vegetation management and other | | | A/B | | Undetermined | | 7.8 |
| | 8.1 |
|
| Total regulatory assets, non-current | | 163.2 |
| | 203.9 |
| | 152.6 |
| | 163.2 |
|
| | | | | | | | | |
| Total regulatory assets | | $ | 187.1 |
| | $ | 204.0 |
| | $ | 193.7 |
| | $ | 187.1 |
|
| | | | | | | | | |
| Regulatory liabilities, current: | | | | | | | | |
| Overcollection of costs to be refunded through rate riders | | A/B | | 2018 | | $ | 14.8 |
| | $ | 33.7 |
| | A/B | | 2018 | | $ | 34.9 |
| | $ | 14.8 |
|
| Total regulatory liabilities, current | | 14.8 |
| | 33.7 |
| | 34.9 |
| | 14.8 |
|
| | | | | | |
| Regulatory liabilities, non-current: | | | | | | | | |
| Estimated costs of removal - regulated property | | Not Applicable | | 132.8 |
| | 126.5 |
| | Not Applicable | | 139.1 |
| | 132.8 |
|
| Deferred income taxes payable through rates | | Various | | 83.4 |
| | — |
| | Various | | 116.3 |
| | 83.4 |
|
| PJM transmission enhancement settlement | | | A | | 2025 | | 16.9 |
| | — |
|
| Postretirement benefits | | B | | Ongoing | | 5.0 |
| | 3.9 |
| | B | | Ongoing | | 6.0 |
| | 5.0 |
|
| Total regulatory liabilities, non-current | | 221.2 |
| | 130.4 |
| | 278.3 |
| | 221.2 |
|
| | | | | | | | | |
| Total regulatory liabilities | | $ | 236.0 |
| | $ | 164.1 |
| | $ | 313.2 |
| | $ | 236.0 |
|
A – Recovery of incurred costs plus rate of return.
B – Recovery of incurred costs without a rate of return.
C – Balance has an offsetting liability resulting in no effect on rate base.
D – 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 $12.5$5.5 million of this net deferral. These items include undercollection of: (i) Distribution Modernization Rider revenues, (ii) certain transmission related costs,decoupling rider (see above), (iii) uncollectible rider and (iii) declines in net revenues resulting from implementation of(iv) energy efficiency programs.rider. It also includes the current portion of the following deferred costs which are described in greater detail below: unbilled fuel, Regulatory Compliance Riderregulatory 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 (v) uncollectible(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 costsrider representrepresents 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. The majority of theseThese costs are being recovered over the three-years beginning November 1, 2017. Recovery of a small portion of the Generation Separation costs, including ongoing costs, will be sought in a future proceeding.three-year period.
Rate case costs represents costs associated with preparing a distribution rate case and ESP.case. DP&L has requestedwas granted recovery of these costs which do not earn a return, as part of its pending distribution rate case filing.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. This plan is currently under development and we plan to seekDP&L requested recovery of these deferred costs which currently do not earn a return, in a regulatory rate proceeding inas part of the near future. Based onDecember 2018 DMP filing with the PUCO precedent, we believe these costs are probable of future recovery in rates.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 20162017 and 2017.2018. 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 filedplans to recover 2016file petitions seeking recovery of each calendar year of storm costs on February 2, 2018 and expects to file to recover 2017 costs later in 2018.the following calendar year. Recovery of these costs is probable by 2019,2020, 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 to customersthrough rates represent deferred income tax assetsliabilities 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. The 2016 regulatory asset of $35.9 million represents the portion of DP&L’s deferred income tax asset that we believed would be recovered through future rates, without interest, based upon established regulatory practices. That 2016 asset was based upon an expected future federal income tax rate of 35%. 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 theirits 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 related regulatory asset became a 83.4 million regulatory liability.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, 20172018 and 2016:2017:
| | | | | December 31, 2017 | | December 31, 2016 | | December 31, 2018 | | December 31, 2017 |
| $ in millions | | | | Composite Rate | | | | Composite Rate | | | | Composite Rate | | | | Composite Rate (a) |
| Regulated: | | | | | | | | | | |
| Transmission | | $ | 414.6 |
| | 2.4% | | $ | 421.1 |
| | 2.3% | | $ | 386.7 |
| | 2.4% | | $ | 414.6 |
| | 2.4% |
| Distribution | | 1,735.9 |
| | 3.4% | | 1,693.5 |
| | 3.2% | | 1,796.4 |
| | 3.2% | | 1,735.9 |
| | 3.4% |
| General | | 31.2 |
| | 3.1% | | 31.6 |
| | 3.2% | | 30.9 |
| | 3.6% | | 31.2 |
| | 3.1% |
| Non-depreciable | | 64.6 |
| | N/A | | 63.5 |
| | N/A | | 60.4 |
| | N/A | | 64.6 |
| | N/A |
| Total regulated | | 2,246.3 |
| | 2,209.7 |
| | | 2,274.4 |
| | 2,246.3 |
| |
| Unregulated: | | | | | | | | | | |
| Other | | 0.2 |
| | 2.7% | | 0.3 |
| | 2.7% | | — |
| | N/A | | 0.2 |
| | 2.7% |
| Non-depreciable | | 0.7 |
| | N/A | | 3.5 |
| | N/A | | — |
| | N/A | | 0.7 |
| | N/A |
| Total unregulated | | 0.9 |
| | 3.8 |
| | | — |
| | 0.9 |
| |
| | | | | | | | | | | |
| Total property, plant and equipment in service | | $ | 2,247.2 |
| | 3.4% | | $ | 2,213.5 |
| | 4.6% | | $ | 2,274.4 |
| | 3.0% | | $ | 2,247.2 |
| | 3.4% |
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. Our legal obligationsThe DP&L AROs are associated with the retirement offor our long-lived assets, consistingretired Hutchings EGU and relate primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities.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.
Changes in the Liability for Generation AROs
| | | $ in millions | | |
| Balance at December 31, 2015 | $ | 5.0 |
| |
| Calendar 2016 | | |
| Additions | 2.7 |
| |
| Accretion expense | 0.3 |
| |
| Settlements | 0.2 |
| |
| Balance at December 31, 2016 | 8.2 |
| $ | 8.2 |
|
| Calendar 2017 | | |
| Accretion expense | 0.1 |
| 0.1 |
|
| Settlements | (0.3 | ) | (0.3 | ) |
| Balance at December 31, 2017 | $ | 8.0 |
| 8.0 |
|
| Calendar 2018 | | |
Settlements (a) | | (3.3 | ) |
| Balance at December 31, 2018 | | $ | 4.7 |
|
| |
| (a) | 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 current year ARO additions.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 $132.8$139.1 million and $126.5$132.8 million in estimated costs of removal at
December 31, 20172018 and 2016,2017, 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
| | | $ in millions | | |
| Balance at December 31, 2015 | $ | 121.8 |
| |
| Calendar 2016 | | |
| Additions | 11.7 |
| |
| Settlements | (7.0 | ) | |
| Balance at December 31, 2016 | 126.5 |
| $ | 126.5 |
|
| Calendar 2017 | | |
| Additions | 12.0 |
| 12.0 |
|
| Settlements | (5.7 | ) | (5.7 | ) |
| Balance at December 31, 2017 | $ | 132.8 |
| 132.8 |
|
| Calendar 2018 | | |
| Additions | | 14.3 |
|
| Settlements | | (8.0 | ) |
| Balance at December 31, 2018 | | $ | 139.1 |
|
Note 5 – Fair Value
The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future.
The table below presents the fair value and cost of our non-derivative instruments at December 31, 20172018 and 2016.2017. See also Note 6 – Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
| | | | | December 31, 2017 | | December 31, 2016 | | December 31, 2018 | | December 31, 2017 |
| $ in millions | | Cost | | Fair Value | | Cost | | Fair Value | | Cost | | Fair Value | | Cost | | Fair Value |
| Assets | | | | | | | | | | | | | | | | |
| Money market funds | | $ | 0.3 |
| | $ | 0.3 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.4 |
| | $ | 0.3 |
| | $ | 0.3 |
|
| Equity securities | | 2.5 |
| | 4.2 |
| | 2.4 |
| | 3.4 |
| | 2.4 |
| | 3.5 |
| | 2.5 |
| | 4.2 |
|
| Debt securities | | 4.3 |
| | 4.3 |
| | 4.4 |
| | 4.4 |
| | 4.1 |
| | 4.0 |
| | 4.3 |
| | 4.3 |
|
| Hedge funds | | 0.1 |
| | 0.2 |
| | — |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.2 |
|
| Real estate | | — |
| | — |
| | 0.3 |
| | 0.3 |
| |
| Tangible assets | | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
|
| Total assets | | $ | 7.3 |
| | $ | 9.1 |
| | $ | 7.6 |
| | $ | 8.7 |
| | $ | 7.1 |
| | $ | 8.1 |
| | $ | 7.3 |
| | $ | 9.1 |
|
| | | | | | | | | | | | | | | | | |
| | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| Liabilities | | | | | | | | | | | | | | | | |
Long-term debt (a) | | $ | 646.6 |
| | $ | 658.4 |
| | $ | 735.7 |
| | $ | 750.1 |
| |
| Long-term debt | | | $ | 586.1 |
| | $ | 593.8 |
| | $ | 646.6 |
| | $ | 658.4 |
|
| |
(a) | Amounts exclude immaterial capital lease obligations in 2016 |
Fair value hierarchyValue Hierarchy
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
Level 1 (quoted prices in active markets for identical assets or liabilities);
Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or
Level 3 (unobservable inputs 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 betweenamong Level 1, and Level 2 or Level 3 of the fair value hierarchy during the years ended December 31, 20172018 and 2016.2017.
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 2020 to 2061.
Master trust assetsTrust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans.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. Any unrealized gains or losses are recorded in AOCI until the securities are sold.
DP&L had $1.7 million ($1.1 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2017 and $1.1 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2016.
During the year ended December 31, 2017, $0.92018, $0.5 million ($0.60.4 million after tax) of various investments were sold to facilitate the distribution of benefits. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.
The fair value of assets and liabilities at December 31, 2018 and 2017 and the respective category within the fair value hierarchy for DP&L was determined as follows:
| | | Assets and Liabilities at Fair Value | |
| $ in millions | | | Fair Value at December 31, 2018 (a) | | Fair Value at December 31, 2017 (a) |
| | | | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| $ in millions | | Fair Value at December 31, 2017 (a) | | Based on
Quoted Prices in
Active Markets | | Other
observable
inputs | | Unobservable inputs | |
| Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Master trust assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Money market funds | | $ | 0.3 |
| | $ | 0.3 |
| | $ | — |
| | $ | — |
| | $ | 0.4 |
| | $ | — |
| | $ | — |
| | $ | 0.4 |
| | $ | 0.3 |
| | $ | — |
| | $ | — |
| | $ | 0.3 |
|
| Equity securities | | 4.2 |
| | — |
| | 4.2 |
| | — |
| | — |
| | 3.5 |
| | — |
| | 3.5 |
| | — |
| | 4.2 |
| | — |
| | 4.2 |
|
| Debt securities | | 4.3 |
| | — |
| | 4.3 |
| | — |
| | — |
| | 4.0 |
| | — |
| | 4.0 |
| | — |
| | 4.3 |
| | — |
| | 4.3 |
|
| Hedge funds | | 0.2 |
| | — |
| | 0.2 |
| | — |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | 0.2 |
| | — |
| | 0.2 |
|
| Real estate | | — |
| | — |
| | — |
| | — |
| |
| Tangible assets | | 0.1 |
| | — |
| | 0.1 |
| | — |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
| | — |
| | 0.1 |
|
| Total Master trust assets | | 9.1 |
| | 0.3 |
| | 8.8 |
| | — |
| | 0.4 |
| | 7.7 |
| | — |
| | 8.1 |
| | 0.3 |
| | 8.8 |
| | — |
| | 9.1 |
|
| Derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest rate hedges | | 1.8 |
| | — |
| | 1.8 |
| | — |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
|
| Total derivative assets | | 1.8 |
| | — |
| | 1.8 |
| | — |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
| | — |
| | 1.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 10.9 |
| | $ | 0.3 |
| | $ | 10.6 |
| | $ | — |
| | $ | 0.4 |
| | $ | 9.2 |
| | $ | — |
| | $ | 9.6 |
| | $ | 0.3 |
| | $ | 10.3 |
| | $ | — |
| | $ | 10.6 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | $ | 658.4 |
| | $ | — |
| | $ | 640.6 |
| | $ | 17.8 |
| | $ | — |
| | $ | 576.1 |
| | $ | 17.7 |
| | $ | 593.8 |
| | $ | — |
| | $ | 640.6 |
| | $ | 17.8 |
| | 658.4 |
|
| | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | | | | | | |
|
|
| Total liabilities | | $ | 658.4 |
| | $ | — |
| | $ | 640.6 |
| | $ | 17.8 |
| | $ | — |
| | $ | 576.1 |
| | $ | 17.7 |
| | $ | 593.8 |
| | $ | — |
| | $ | 640.6 |
| | $ | 17.8 |
| | $ | 658.4 |
|
| |
| (a) | Includes credit valuation adjustment |
| |
(b) | Amounts exclude immaterial capital lease obligations |
The fair value of assets and liabilities at December 31, 2016 and the respective category within the fair value hierarchy for DP&L was determined as follows:
|
| | | | | | | | | | | | | | | | |
| Assets and Liabilities at Fair Value |
| | | | | Level 1 | | Level 2 | | Level 3 |
| $ in millions | | Fair Value at December 31, 2016 (a) | | Based on
Quoted Prices in
Active Markets | | Other
observable
inputs | | Unobservable inputs |
| Assets | | | | | | | | |
| Master trust assets | | | | | | | | |
| Money market funds | | $ | 0.4 |
| | $ | 0.4 |
| | $ | — |
| | $ | — |
|
| Equity securities | | 3.4 |
| | — |
| | 3.4 |
| | — |
|
| Debt securities | | 4.4 |
| | — |
| | 4.4 |
| | — |
|
| Hedge funds | | 0.1 |
| | — |
| | 0.1 |
| | — |
|
| Real estate | | 0.3 |
| | — |
| | 0.3 |
| | — |
|
| Tangible assets | | 0.1 |
| | — |
| | 0.1 |
| | — |
|
| | | | | | | | | |
| Total assets | | $ | 8.7 |
| | $ | 0.4 |
| | $ | 8.3 |
| | $ | — |
|
| | | | | | | | | |
| Liabilities | | | | | | | | |
Long-term debt (b) | | $ | 750.1 |
| | $ | — |
| | $ | 732.1 |
| | $ | 18.0 |
|
| | |
|
| | | | | | |
| Total liabilities | | $ | 750.1 |
| | $ | — |
| | $ | 732.1 |
| | $ | 18.0 |
|
| |
(a) | Includes credit valuation adjustment |
| |
(b) | Amounts exclude immaterial capital lease obligations |
Our financial instruments are valued using the market approach in the following categories:
Level 1 inputs are used for financial contracts, such as 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 hedges.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 used to value some debt which isconsidered a Level 3 input because the notes are not publicly traded. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.long-term debt is fair valued for disclosure purposes only.
Approximately 100%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 for asbestos, ash landfill, underground storage tanks,was $4.7 million and river structures decreased by a net amount of $0.2$8.0 million ($0.1 million after tax) and increased by a net amount of $3.2 million ($2.1 million after tax)at December 31, 2018 and 2017, and 2016, respectively. See Note 4 – Property, Plant and Equipment for more information about AROs.
Note 6 – Derivative Instruments and Hedging Activities
In the normal course of business, DP&L enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes.
DP&L's interest rate swaps are designated as a cash flow hedge. At December 31, 20172018 and 2016,2017, the principal balance of the interest rate hedges was $140.0 million and $200.0 million.million, respectively.
Cash flow hedgesFlow 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 $200.0$140.0 million variable interest rate tax-exempt First Mortgage Bonds. The interest rate swaps have a combined notional amount of $200.0$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:
| | | | | Years ended December 31, | | | | Years ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| $ in millions (net of tax) | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges | | Power | | Interest Rate
Hedges |
| Beginning accumulated derivative gain / (loss) in AOCI | | $ | (4.3 | ) | | $ | 1.6 |
| | $ | 9.2 |
| | $ | 2.0 |
| | $ | 0.2 |
| | $ | 2.6 |
| | $ | 1.4 |
| | $ | (4.3 | ) | | $ | 1.6 |
| | $ | 9.2 |
| | $ | 2.0 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Net gains / (losses) associated with current period hedging transactions | | 10.7 |
| | 1.7 |
| | 15.7 |
| | 0.4 |
| | 18.2 |
| | — |
| | (0.1 | ) | | 11.9 |
| | 0.5 |
| | 15.7 |
| | 0.4 |
|
| Net gains / (losses) reclassified to earnings: | | | | | | | | | | | | | | | | | | | | | | |
| Interest expense | | — |
| | (0.7 | ) | | — |
| | (0.8 | ) | | — |
| | (0.6 | ) | | (0.7 | ) | | — |
| | (0.7 | ) | | — |
| | (0.8 | ) |
| Loss from discontinued operations | | (5.5 | ) | | — |
| | (29.2 | ) | | — |
| | (9.2 | ) | | — |
| | — |
| | (5.5 | ) | | — |
| | (29.2 | ) | | — |
|
| Transfer of generation assets to subsidiary of parent | | $ | (2.1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | — |
| | (2.1 | ) | | — |
| | — |
| | — |
|
| Ending accumulated derivative gain / (loss) in AOCI | | $ | (1.2 | ) | | $ | 2.6 |
| | $ | (4.3 | ) | | $ | 1.6 |
| | $ | 9.2 |
| | $ | 2.0 |
| | $ | 0.6 |
| | $ | — |
| | $ | 1.4 |
| | $ | (4.3 | ) | | $ | 1.6 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Portion expected to be reclassified to earnings in the next twelve months | |
| | $ | (0.7 | ) | | | | | | | | | | $ | 0.7 |
| | | | | | | | |
| | | | | | | | | | | | | | |
| Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) | |
| | 32 |
| | | | | | | | | | 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, | | December 31, |
| | Hedging Designation | | Balance sheet classification | | 2017 | | 2016 | Hedging Designation | | Balance sheet classification | | 2018 | | 2017 |
| Interest Rate Hedges in an Asset Position | Cash Flow Hedge | | Other Deferred Assets | | | | | |
| 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 | | $ | 1.8 |
| | $ | 1.2 |
| | $ | 0.9 |
| | $ | — |
|
| | | | | | | | | |
| Interest Rate Hedges in a Liability Position | Cash Flow Hedge | | Other Current Liabilities | | | | | |
| Interest rate hedges in a non-current asset position | | Cash Flow Hedge | | Other deferred assets | | | | |
| Gross Fair Value as presented in the Balance Sheets | | $ | — |
| | $ | 0.7 |
| | $ | 0.6 |
| | $ | 1.5 |
|
Note 7 – DebtLong-term debt
Long-term debt is as follows:
| | | Long-term debt | | | | | | | | |
| $ in millions | | Interest Rate | | Maturity | | December 31, 2017 | | December 31, 2016 | | Interest Rate | | Maturity | | December 31, 2018 | | December 31, 2017 |
| Term loan - rates from: 4.01% - 4.60% (a) and 4.00% - 4.01% (b) | | 2022 | | $ | 440.6 |
| | $ | 445.0 |
| |
| Tax-exempt First Mortgage Bonds | | 4.8% | | 2036 | | — |
| | 100.0 |
| |
| Tax-exempt First Mortgage Bonds - rates from: 1.52% - 1.92% (a) and 1.29% - 1.42% (b) | | 2020 | | 200.0 |
| | 200.0 |
| |
| Term loan - rates from: 3.57% - 4.82% (a) and 4.00% - 4.60% (b) | | | 2022 | | $ | 436.1 |
| | $ | 440.6 |
|
| Tax-exempt First Mortgage Bonds - rates from: 2.49% - 2.93% (a) and 1.29% - 1.42% (b) | | | 2020 | | 140.0 |
| | 200.0 |
|
| U.S. Government note | | 4.2% | | 2061 | | 17.8 |
| | 18.0 |
| | 4.2% | | 2061 | | 17.7 |
| | 17.8 |
|
| Capital leases | |
| |
| | — |
| | 0.4 |
| |
| Debt classified as held-for-sale | | — |
| | (13.4 | ) | |
| Unamortized deferred financing costs | | (9.8 | ) | | (11.7 | ) | | (6.3 | ) | | (9.8 | ) |
| Unamortized debt discount | | (2.0 | ) | | (2.2 | ) | | (1.4 | ) | | (2.0 | ) |
| Total long-term debt | | 646.6 |
| | 736.1 |
| | 586.1 |
| | 646.6 |
|
| Less: current portion | | (4.6 | ) | | (4.6 | ) | | (4.6 | ) | | (4.6 | ) |
| Long-term debt, net of current portion | | $ | 642.0 |
| | $ | 731.5 |
| | $ | 581.5 |
| | $ | 642.0 |
|
| |
| (a) | Range of interest rates for the year ended December 31, 2017.2018. |
| |
| (b) | Range of interest rates for the year ended December 31, 2016.2017. |
At December 31, 2017,2018, maturities of long-term debt are summarized as follows:
| | | Due during the years ending December 31, | | |
| $ in millions | | |
| 2018 | $ | 4.6 |
| |
| 2019 | 4.6 |
| $ | 4.6 |
|
| 2020 | 204.6 |
| 144.7 |
|
| 2021 | 4.6 |
| 4.7 |
|
| 2022 | 422.9 |
| 422.8 |
|
| 2023 | | 0.2 |
|
| Thereafter | 17.1 |
| 16.8 |
|
| | 658.4 |
| 593.8 |
|
| Unamortized discounts and premiums, net | (2.0 | ) | (1.4 | ) |
| Deferred financing costs, net | | (6.3 | ) |
| Total long-term debt | $ | 656.4 |
| $ | 586.1 |
|
Significant transactionsTransactions
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 May 26, 2017,March 30, 2018, DP&L commenced a tender offer to purchase any and allredemption of the$60.0 million of outstanding 4.8% tax-exempttax exempt First Mortgage Bonds due 2020 at par value (plus accrued and unpaid interest). By June 23, 2017, or the expiration date of the tender, $8.1 million of the outstandingThese bonds were tendered. On June 26, 2017, DP&L accepted all of the tendered bonds, redeemed and retired them. On July 7, 2017, DP&L notified the Ohio Air Quality Development Authority and the Trustee of the same First Mortgage Bonds that DP&L was going to call at par value (plusplus accrued and unpaid interest) $21.9 million of these bonds. This call was completedinterest on August 7, 2017. On September 28, 2017, DP&L issued an irrevocable call notice to purchase all of the remaining outstanding 4.8% tax-exempt First Mortgage Bonds at par value (plus accrued and unpaid interest). As of SeptemberApril 30, 2017, all of the bonds were either redeemed or defeased. This was done to facilitate Generation Separation and the release of the DP&L
generation assets from the lien of DP&L's First and Refunding Mortgage. The redemption of the $70.0 million principal amount of bonds was completed2018 with cash on October 30, 2017.
On February 21, 2017, DP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modified the definition of Consolidated Net Worth in each agreement (which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter ending December 31, 2016 and thereafter. With this amendment, DP&L was able to ensure compliance with theTotal Debt to Total Capitalization ratio through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement (before any amendment), the required Total Debt to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total Debt to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00. After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L (or from October 1, 2017 through September 30, 2018). Generation Separation occurred on October 1, 2017.
On December 31, 2016, DP&L borrowed $5.0 million from DPL at an interest rate of 3.02%. The notes were due on or before January 30, 2017 and were repaid on the maturity date.
On August 24, 2016, DP&L refinanced its 1.875% First Mortgage Bonds due 2016, with a variable rate Term Loan B of $445.0 million maturing on August 24, 2022 and secured by a pledge of DP&L First Mortgage Bonds. The variable rate on the loan is calculated based on LIBOR plus a spread of 3.25%, with a LIBOR floor of 0.75%. Up to the maturity date but not starting until March 31, 2017, the loan amortizes 0.25% of the initial principal balance quarterly and contains covenants and restrictions that are generally consistent with existing DP&L credit agreements.hand.
Debt covenantsCovenants and restrictionsRestrictions
DP&L’sunsecured 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, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L)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. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.
DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the issuance of the $200.0 million of variable rate tax-exempt First Mortgage Bonds, dated as of August 1, 2015, containing representations, warranties and covenants consistent with those contained in DP&L's revolving credit facilities loan documents) have two financial covenants. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’sTotal Debt to Total Capitalization mayratio shall not be greater than 0.65 to 1.00 at any time; and, on and after1.00; except that, the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, which occurred October 1, 2017, DP&L’s Total Debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time. Except that after separation required compliance with this financial covenantratio shall be suspended (a)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&Lmaintains a rating of BBB- (or in the case of Moody’s Investors Service, Inc. Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms As of the revolving credit facility or (b)December 31, 2018, DP&L's ratings meet those requirements and this ratio is suspended for the time period January 1, 2017 toquarter ended December 31, 2017 (as modified by the amendment described below) if DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization covenant is calculated as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s net worth and total debt.2018.
On February 21, 2017, The second financial covenant measures EBITDA to Interest Expense. The TotalDP&L and its lenders amended DP&L’s revolving credit agreement and Bond Purchase and Covenant Agreement. These amendments modifiedConsolidated EBITDA to Consolidated Interest Charges ratio is calculated, at the definitionend of Consolidated Net Worth in each agreement
(which is used for measuring the Total Debt to Total Capitalization ratio under each of the agreements), to exclude, through March 31, 2018, non-cash charges related directly to impairments of coal generation assets in DP&L's fiscal quarter, ending December 31, 2016 and thereafter. With this amendment, DP&L was able to ensure compliance withby dividing consolidated EBITDA for theTotal Debt to Total Capitalization four prior fiscal quarters by the consolidated interest charges for the same period. The ratio, through October 1, 2017, the date Generation Separation occurred. After Generation Separation, and per the terms of the original agreement, (before any amendment), the required Total Debtis to Total Capitalization ratio increased from 0.65 to 1.00 to 0.75be not less than 2.50 to 1.00. On September 30, 2017, DP&L's adjusted (excluding impairments) Total DebtThis covenant was met with a ratio of 8.09 to Total Capitalization was 0.61 to 1.00 and as of December 31, 2017 it was 0.67 to 1.00. After Generation Separation occurred, the calculation of this covenant is on an unadjusted basis. The amendment also changed, for each agreement, the dates after Generation Separation during which compliance with the Total Capitalization ratio detailed above will be suspended if long-term indebtedness, as determined by the PUCO, is less than or equal to $750.0 million. As noted above this time period previously was January 1, 2017 to December 31, 2017, and is now the twelve months immediately subsequent to the separation of the generation assets from DP&L (or from October 1, 2017 through September 30, 2018). Generation Separation occurred on October 1, 2017.2018.
As of December 31, 2017, DP&L was in compliance with all debt covenantsdoes, including the financial covenants described above and did not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPLDPL.
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.
Note 8 – Income Taxes
DP&L’s components of income tax expense on continuing operations were as follows:
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Computation of tax expense | | | | | | | | | | | | |
| Federal income tax expense (a) | | $ | 31.0 |
| | $ | 50.1 |
| | $ | 65.8 |
| | $ | 22.2 |
| | $ | 31.0 |
| | $ | 50.1 |
|
| Increases (decreases) in tax resulting from: | | | | | | | | | | | | |
| State income taxes, net of federal effect | | 0.4 |
| | 0.4 |
| | 0.4 |
| | 0.6 |
| | 0.4 |
| | 0.4 |
|
| Depreciation of AFUDC - Equity | | 1.2 |
| | 3.0 |
| | (3.1 | ) | |
| Depreciation of flow-through differences | | | (4.3 | ) | | 1.2 |
| | 3.0 |
|
| Investment tax credit amortized | | (0.3 | ) | | (0.4 | ) | | (0.4 | ) | | (0.3 | ) | | (0.3 | ) | | (0.4 | ) |
| Accrual (settlement) for open tax years | | (0.5 | ) | | 3.4 |
| | — |
| | — |
| | (0.5 | ) | | 3.4 |
|
Other, net (b) | | (0.7 | ) | | (10.5 | ) | | (3.7 | ) | | (0.5 | ) | | (0.7 | ) | | (10.5 | ) |
| Total tax expense | | $ | 31.1 |
| | $ | 46.0 |
| | $ | 59.0 |
| | $ | 17.7 |
| | $ | 31.1 |
| | $ | 46.0 |
|
| |
| |
| |
| |
| |
| |
|
| Components of tax expense | | | | | | | | | | | | |
| Federal - current | | $ | 13.5 |
| | $ | 37.7 |
| | $ | 68.3 |
| | $ | 1.4 |
| | $ | 13.5 |
| | $ | 37.7 |
|
| State and Local - current | | 0.2 |
| | 0.5 |
| | 0.9 |
| | — |
| | 0.2 |
| | 0.5 |
|
| Total current | | 13.7 |
| | 38.2 |
| | 69.2 |
| | 1.4 |
| | 13.7 |
| | 38.2 |
|
| | | | | | | | | | | | | |
| Federal - deferred | | 17.0 |
| | 7.7 |
| | (9.9 | ) | | 15.5 |
| | 17.0 |
| | 7.7 |
|
| State and local - deferred | | 0.4 |
| | 0.1 |
| | (0.3 | ) | | 0.8 |
| | 0.4 |
| | 0.1 |
|
| Total deferred | | 17.4 |
| | 7.8 |
| | (10.2 | ) | | 16.3 |
| | 17.4 |
| | 7.8 |
|
| Total tax expense | | $ | 31.1 |
| | $ | 46.0 |
| | $ | 59.0 |
| | $ | 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 $0.0 million, $(0.4)$(0.7) million and $0.1$(0.4) million in the years ended December 31, 2017 2016 and 2015,2016, 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, 20172018, 20162017 and 20152016:
| | | | | Years ended December 31, | | Years ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Statutory Federal tax rate | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 21.0 | % | | 35.0 | % | | 35.0 | % |
| State taxes, net of Federal tax benefit | | 0.4 | % | | 0.3 | % | | 0.2 | % | | 0.6 | % | | 0.4 | % | | 0.3 | % |
| AFUDC - Equity | | 1.4 | % | | 2.1 | % | | (1.7 | )% | | (0.1 | )% | | 1.4 | % | | 2.1 | % |
| Amortization of investment tax credits | | (0.4 | )% | | (0.3 | )% | | (0.2 | )% | | (0.3 | )% | | (0.4 | )% | | (0.3 | )% |
| Depreciation of flow-through differences | | | (4.0 | )% | | — | % | | — | % |
| Other - net | | (1.3 | )% | | (5.1 | )% | | (2.1 | )% | | (0.2 | )% | | (1.3 | )% | | (5.1 | )% |
| Effective tax rate | | 35.1 | % | | 32.0 | % | | 31.2 | % | | 17.0 | % | | 35.1 | % | | 32.0 | % |
Deferred Income Taxes
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and (b) operating loss carryforwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
| | Components of Deferred Tax Assets and Liabilities | | | | December 31, | | December 31, |
| $ in millions | | 2017 | | 2016 | | 2018 | | 2017 |
| Net non-current assets / (liabilities) | | | | | | | | |
| Depreciation / property basis | | $ | (126.5 | ) | | $ | (238.0 | ) | | $ | (130.6 | ) | | $ | (126.5 | ) |
| Income taxes recoverable / (payable) | | 11.0 |
| | (12.2 | ) | |
| Income taxes recoverable | | | 25.0 |
| | 11.0 |
|
| Regulatory assets | | (23.9 | ) | | (9.1 | ) | | (16.2 | ) | | (23.9 | ) |
| Investment tax credit | | 0.4 |
| | 0.4 |
| | 0.5 |
| | 0.4 |
|
| Compensation and employee benefits | | 17.6 |
| | (0.3 | ) | | 0.3 |
| | 17.6 |
|
| Other | | (9.6 | ) | | (7.7 | ) | | (10.7 | ) | | (9.6 | ) |
| Net non-current liabilities | | $ | (131.0 | ) | | $ | (266.9 | ) | | $ | (131.7 | ) | | $ | (131.0 | ) |
U. S
U.S. Tax Reform
On December 22, 2017, the U.S. enacted the TCJA. The TCJA significantly changes U.S. corporate income tax law.
WeIn 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 reflectreflected the income tax effects of U.S. tax reform for which the accounting iswas complete and provisional amounts for those impacts for which the accounting under FASC 740 iswas incomplete, but a reasonable estimate could be determined.
We have calculatedcompleted our best estimatecalculation of the impact of the TCJA in our income tax provision for the year ended December 31, 20172018 in accordance with our understanding of the TCJA and guidance available as of the date of this filing.
Certain deferred tax assets and liabilities were remeasured as the rates changed from 35% to 21%. The most material deferred taxes to be remeasured related to property, plant and equipment. The As a result of this remeasurement, ofcertain deferred tax assets and liabilities related to regulated utility property of $17.0 million and $135.2 million wasat December 31, 2018 and 2017 were recorded as a regulatory liability,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 was a non-cash adjustment. Additional time is requiredresulted in an additional $10.0 million return of capital to finalize remeasurement effectsDPL in accordance with GAAP.
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, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Tax expense / (benefit) | | $ | 4.0 |
| | $ | (7.0 | ) | | $ | 7.5 |
| | $ | (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:
| | | $ in millions | | |
| Balance at December 31, 2015 | $ | 3.0 |
| |
| Calendar 2016 | | |
| Tax positions taken during prior period | 3.4 |
| |
| Lapse of Statute of Limitations | (1.5 | ) | |
| Balance at December 31, 2016 | 4.9 |
| $ | 4.9 |
|
| Calendar 2017 | | |
| Tax positions taken during prior period | — |
| — |
|
| Lapse of Statute of Limitations | (0.1 | ) | (0.1 | ) |
| Balance at December 31, 2017 | $ | 4.8 |
| 4.8 |
|
| Calendar 2018 | | |
| Tax positions taken during prior period | | — |
|
| Lapse of Statute of Limitations | | — |
|
| Balance at December 31, 2018 | | $ | 4.8 |
|
Of the December 31, 20172018 balance of unrecognized tax benefits, $0.9$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 plansContribution 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 $2,300$2,400 for 20172018 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 and $4.9 million infor the years ended December 31, 2018, 2017 2016 and 2015,2016, 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. For 2017, the annual bonus amount is yet to be determined and paid; pending the results of negotiations with the bargaining unit.
Defined benefit plBenefit 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. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan. 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 benefitsBenefits
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 $12.7$9.2 million and $15.8$12.7 million at December 31, 20172018 and 2016,2017, 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, 20172018 and 2016.2017. 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 $1.1$1.8 million and $1.3$1.1 million of costs billed to the service companyService Company for the years ended December 31, 2018 and 2017 or $3.3 million and 2016 or $0.7 million of costs billed to AES Ohio Generation for the yearyears ended December 31, 2018 and 2017.
| | | $ in millions | | Years ended December 31, | | Years ended December 31, |
| Change in benefit obligation | | 2017 | | 2016 | | 2018 | | 2017 |
| Benefit obligation at January 1 | | $ | 419.6 |
| | $ | 410.8 |
| | $ | 436.9 |
| | $ | 419.6 |
|
| Service cost | | 5.7 |
| | 5.7 |
| | 6.1 |
| | 5.7 |
|
| Interest cost | | 14.2 |
| | 14.7 |
| | 13.8 |
| | 14.2 |
|
| Plan amendments | | | 5.1 |
| | — |
|
| Plan curtailment | | 3.0 |
| | 2.5 |
| | — |
| | 3.0 |
|
| Actuarial loss | | 28.1 |
| | 9.0 |
| |
| Actuarial (gain) / loss | | | (34.6 | ) | | 28.1 |
|
| Benefits paid | | (33.7 | ) | | (23.1 | ) | | (40.8 | ) | | (33.7 | ) |
| Benefit obligation at December 31 | | 436.9 |
| | 419.6 |
| | 386.5 |
| | 436.9 |
|
| | | | | | | | | |
| Change in plan assets | | | | | | | | |
| Fair value of plan assets at January 1 | | 341.0 |
| | 345.4 |
| | 357.5 |
| | 341.0 |
|
| Actual return on plan assets | | 44.8 |
| | 13.3 |
| | (11.7 | ) | | 44.8 |
|
| Employer contributions | | 5.4 |
| | 5.4 |
| | 7.9 |
| | 5.4 |
|
| Benefits paid | | (33.7 | ) | | (23.1 | ) | | (40.8 | ) | | (33.7 | ) |
| Fair value of plan assets at December 31 | | 357.5 |
| | 341.0 |
| | 312.9 |
| | 357.5 |
|
| | | | | | | | | |
| Unfunded status of plan | | $ | (79.4 | ) | | $ | (78.6 | ) | | $ | (73.6 | ) | | $ | (79.4 | ) |
| |
| |
| |
| |
|
| | | December 31, | | December 31, |
| Amounts recognized in the Balance sheets | | 2017 | | 2016 | | 2018 | | 2017 |
| Current liabilities | | $ | (0.4 | ) | | $ | (0.4 | ) | | $ | (0.4 | ) | | $ | (0.4 | ) |
| Non-current liabilities | | (79.0 | ) | | (78.2 | ) | | (73.2 | ) | | (79.0 | ) |
| Net liability at end of year | | $ | (79.4 | ) | | $ | (78.6 | ) | | $ | (73.6 | ) | | $ | (79.4 | ) |
| | | | | | | | | |
| Amounts recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax | | | | | | | | |
| Components: | | | | | | | | |
| Prior service cost | | $ | 6.7 |
| | $ | 8.8 |
| | $ | 10.4 |
| | $ | 6.7 |
|
| Net actuarial loss | | 148.3 |
| | 108.9 |
| | 137.2 |
| | 148.3 |
|
| Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax | | $ | 155.0 |
| | $ | 117.7 |
| | $ | 147.6 |
| | $ | 155.0 |
|
| Recorded as: | |
| |
| |
| |
|
| Regulatory asset | | $ | 92.2 |
| | $ | 97.1 |
| | $ | 87.3 |
| | $ | 92.2 |
|
| Accumulated other comprehensive income | | 62.8 |
| | 20.6 |
| | 60.3 |
| | 62.8 |
|
| Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax | | $ | 155.0 |
| | $ | 117.7 |
| | $ | 147.6 |
| | $ | 155.0 |
|
The accumulated benefit obligation for our defined benefit pension plans was $428.3$378.7 million and $409.2$428.3 million at December 31, 2018 and 2017, and 2016, respectively.
The net periodic benefit cost of the pension plans was:
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Service cost | | $ | 5.7 |
| | $ | 5.7 |
| | $ | 7.1 |
| | $ | 6.1 |
| | $ | 5.7 |
| | $ | 5.7 |
|
| Interest cost | | 14.2 |
| | 14.7 |
| | 17.3 |
| | 13.8 |
| | 14.2 |
| | 14.7 |
|
| Expected return on assets | | (22.8 | ) | | (22.8 | ) | | (22.6 | ) | | (21.2 | ) | | (22.8 | ) | | (22.8 | ) |
Plan curtailment | | 5.6 |
| | 5.7 |
| | — |
| | — |
| | 5.6 |
| | 5.7 |
|
| Amortization of unrecognized: | | | | | | | | | | | | |
| Actuarial loss | | 8.7 |
| | 7.2 |
| | 9.8 |
| | 9.4 |
| | 8.7 |
| | 7.2 |
|
| Prior service cost | | 1.5 |
| | 3.0 |
| | 3.3 |
| | 1.4 |
| | 1.5 |
| | 3.0 |
|
| Net periodic benefit cost | | $ | 12.9 |
| | $ | 13.5 |
| | $ | 14.9 |
| | $ | 9.5 |
| | $ | 12.9 |
| | $ | 13.5 |
|
| | | | | | | | | | | | | |
| Rates relevant to each year's expense calculations | | | | | | | | | | | | |
| Discount rate | | 4.28 | % | | 4.49 | % | | 4.02 | % | | 3.66 | % | | 4.28 | % | | 4.49 | % |
| Expected return on plan assets | | 6.50 | % | | 6.50 | % | | 6.50 | % | | 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, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Net actuarial loss / (gain) | | $ | 9.1 |
| | $ | 20.9 |
| | $ | (3.0 | ) | |
| Prior service cost | | — |
| | — |
| | — |
| |
| Plan curtailment | | (5.6 | ) | | (5.7 | ) | | — |
| |
| Net actuarial loss | | | $ | 3.4 |
| | $ | 9.1 |
| | $ | 20.9 |
|
Plan curtailment (a) | | | — |
| | (5.6 | ) | | (5.7 | ) |
| Reversal of amortization item: | | | | | | | | | | | | |
| Net actuarial loss | | (8.7 | ) | | (7.2 | ) | | (9.8 | ) | | (9.4 | ) | | (8.7 | ) | | (7.2 | ) |
| Prior service cost | | (1.5 | ) | | (3.0 | ) | | (3.3 | ) | | (1.4 | ) | | (1.5 | ) | | (3.0 | ) |
| Total recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities | | $ | (6.7 | ) | | $ | 5.0 |
| | $ | (16.1 | ) | | $ | (7.4 | ) | | $ | (6.7 | ) | | $ | 5.0 |
|
| | | | | | | | | | | | | |
| Total recognized in net periodic benefit cost and Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities | | $ | 6.2 |
| | $ | 18.5 |
| | $ | (1.2 | ) | | $ | 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. |
Estimated amounts that will be amortized from AOCI, Regulatory assetsSignificant Gains and Regulatory liabilities into net periodicLosses Related to Changes in the Benefit Obligation
The actuarial gain of $34.6 million decreased the benefit costs duringobligation for the year ended December 31, 2018 are:
|
| | | | |
| $ in millions | | Pension |
| Actuarial loss | | $ | 9.4 |
|
| Prior service cost | | $ | 1.4 |
|
Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
At December 31, 2017,2018, we are decreasingmaintaining our long-term rate of return assumption toof 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, 2017,2018, we have decreasedincreased our assumed discount rate to 3.66%4.35% from 4.28%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 20182019 pension expense of approximately $3.4$3.2 million. A one percent decrease in the rate of return assumption for pension would result in an increase in 20182019 pension expense of approximately $3.43.2 million. A 25-basis point increase in the discount rate for pension would result in a decrease of approximately
$0.6 $0.1 million to 20182019 pension expense. A 25-basis point decrease in the discount rate for pension would result in an increase of approximately $0.6$0.4 million to 20182019 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, 2017.2018. 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.
Effective January 1, 2016, we applied a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 – Overview and Summary of Significant Accounting Policies for more information.
In future periods, differences in the actual return on pension 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 2016 and 20152016 were:
| | | Benefit Obligation Assumptions | | Pension | | Pension |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| Discount rate for obligations | | 3.66% | | 4.28% | | 4.49% | | 4.35% | | 3.66% | | 4.28% |
| Rate of compensation increases | | 3.94% | | 3.94% | | 3.94% | | 3.94% | | 3.94% | | 3.94% |
Pension plan assetsPlan Assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.
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 2017:2018:
| | | | | Long-Term
Mid-Point
Target
Allocation | | Percentage of plan assets as of December 31, | | Long-Term
Mid-Point
Target
Allocation | | Percentage of plan assets as of December 31, |
| Asset category | | 2017 | | 2016 | | 2018 | | 2017 |
| Equity Securities | | 38% | | 35% | | 37% | | 38% | | 33% | | 35% |
| Debt Securities | | 56% | | 55% | | 53% | | 56% | | 58% | | 55% |
| Cash and Cash Equivalents | | | —% | | 1% | | —% |
| Real Estate | | 6% | | 10% | | 10% | | 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 |
| $ in millions | | Market Value 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. |
| |
| (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 | | $ in millions | | Market Value at December 31, 2017 | | Quoted prices
in active
markets for
identical assets | | Significant
observable
inputs | | Significant
unobservable
inputs | | Market Value 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) | | | | (Level 1) | | (Level 2) | | (Level 3) |
| Mutual funds: | | | | | | | | | | | | | | | | |
U.S. equities (a) | | $ | 78.2 |
| | $ | 78.2 |
| | $ | — |
| | $ | — |
| | $ | 78.2 |
| | $ | 78.2 |
| | $ | — |
| | $ | — |
|
International equities (a) | | 46.3 |
| | 46.3 |
| | — |
| | — |
| | 46.3 |
| | 46.3 |
| | — |
| | — |
|
Fixed income (b) | | 163.3 |
| | 163.3 |
| | — |
| | — |
| | 163.3 |
| | 163.3 |
| | — |
| | — |
|
| Fixed income securities: | |
| |
| | | | | | | | | | | | |
| U.S. Treasury securities | | 33.5 |
| | 33.5 |
| | — |
| | — |
| | 33.5 |
| | 33.5 |
| | — |
| | — |
|
Other investments: | |
| | | |
| | | |
| |
| | | |
|
Core property collective fund (c) | | 36.2 |
| | — |
| | 36.2 |
| | — |
| | 36.2 |
| | — |
| | 36.2 |
| | — |
|
| Total pension plan assets | | $ | 357.5 |
| | $ | 321.3 |
| | $ | 36.2 |
| | $ | — |
| | $ | 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. |
The fair values of our pension plan assets at December 31, 2016 by asset category are as follows:Pension Funding
|
| | | | | | | | | | | | | | | | |
| Fair Value Measurements for Pension Plan Assets at December 31, 2016 |
| $ in millions | | Market Value at December 31, 2016 | | 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) | | $ | 81.4 |
| | $ | 81.4 |
| | $ | — |
| | $ | — |
|
International equities (a) | | 44.4 |
| | 44.4 |
| | — |
| | — |
|
Fixed income (b) | | 151.1 |
| | 151.1 |
| | — |
| | — |
|
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 31.0 |
| | 31.0 |
| | — |
| | — |
|
Other investments: (c) | |
| |
| | | |
|
| Core property collective fund | | 33.1 |
| | — |
| | 33.1 |
| | — |
|
| Common collective fund | | — |
| | — |
| | — |
| | — |
|
| Total pension plan assets | | $ | 341.0 |
| | $ | 307.9 |
| | $ | 33.1 |
| | $ | — |
|
| |
(a) | This category includes investments in equity securities of large, small and medium sized U.S. companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
| |
(b) | This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund. |
| |
(c) | This category represents a property fund that invests in commercial real estate. 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 2016 and 2015.2016.
We expect to make contributions of $0.4 million to our SERP in 20182019 to cover benefit payments. We madealso expect to make contributions of $7.5 million to our pension plan during January 2018.2019.
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 99%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 $7.5$5.4 million in 2018,2019, which includes $2.2$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 | | Pension |
| 2018 | | $ | 28.4 |
| |
| 2019 | | $ | 28.2 |
| | $ | 26.7 |
|
| 2020 | | $ | 27.9 |
| | $ | 26.5 |
|
| 2021 | | $ | 27.6 |
| | $ | 26.3 |
|
| 2022 | | $ | 27.3 |
| | $ | 26.0 |
|
| 2023 - 2027 | | $ | 131.3 |
| |
| 2023 | | | $ | 25.9 |
|
| 2024 - 2028 | | | $ | 125.1 |
|
Note 10 – Equity
Redeemable Preferred Stock
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 250,000,00050,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2017.2018. All common shares are held by DP&L’s parent, DPL.
As partEquity Settlement of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance. After the fixed-asset impairments
recorded during the first quarter of 2017 and the second and fourth quarters of 2016 and as of December 31, 2017, DP&L's equity ratio was 33% and its retained earnings balance was negative. It is unknown what impact, if any, this will have on DP&L.
Equity settlement of related party payableRelated 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 DPLDPL. . In connection with Generation Separation, DP&L recorded $86.2 million as a return of capital. See Note 1314 – 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, 2017,2018, DP&L could be responsible for the repayment of 4.9%, or $70.6$68.1 million, of a $1,440.8$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. At DecemberOne 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, 2017, we2018. We do not expect these events to have no knowledgea material impact on our financial condition, results of such a default.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, 2017,2018, these include:
| | | | | Payments due in: | | Payments due in: |
| $ in millions | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years | | Total | | Less than
1 year | | 2 - 3
years | | 4 - 5
years | | More than
5 years |
| Electricity purchase commitments | | $ | 370.9 |
| | $ | 178.5 |
| | $ | 171.2 |
| | $ | 21.2 |
| | $ | — |
| | $ | 209.4 |
| | $ | 139.5 |
| | $ | 69.9 |
| | $ | — |
| | $ | — |
|
| Purchase orders and other contractual obligations | | $ | 73.0 |
| | $ | 18.9 |
| | $ | 27.1 |
| | $ | 27.0 |
| | $ | — |
| | $ | 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, 2017,2018, 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.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, 2017,2018, cannot be reasonably determined.
Environmental Matters
DP&L'sfacilities and operations are subject to a wide range of federal, state and local environmental regulationslaws, rules and laws.regulations. The environmental issues that may affect us include: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 the operationour results of the power stations.operations, financial condition or cash flows.
Note 12 – Related Party Transactions
Service Company
Effective January 1, 2014, the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services 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 plansPlans
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 2016 and 2015,2016, 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 and options to purchase shares of AES common stock, however no stock options were granted in 2016. All such components vest ratably over a three-year period and the terms of the AES restricted stock units issued prior to 2011 also include a two-year minimum holding period after the awards vest. Awards made in 2011 and for subsequent years are not subject to a two-year holding period. In addition, theThe 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 and 2015 was $0.4$0.3 million, $0.5$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 theseour related party transactions:
| | | | | Years ended December 31, | | Years ended December 31, |
| $ in millions | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
DP&L revenues: | | | | | | | |
Sales to DPLER (including MC Squared) (a) | | $ | — |
| | $ | — |
| | $ | 303.3 |
| |
DP&L Cost of revenues: | | | | | | | | | | | | |
| Fuel and power purchased from AES Ohio Generation | | $ | 5.4 |
| | $ | 8.7 |
| | $ | 5.2 |
| | $ | — |
| | $ | 5.4 |
| | $ | 8.7 |
|
DP&L Operation & Maintenance Expenses: | | | | | | | | | | | | |
Premiums charged for insurance services provided by MVIC (b) | | $ | 3.1 |
| | $ | 3.4 |
| | $ | 3.2 |
| |
Expense recoveries for services provided to DPLER (c) | | $ | — |
| | $ | — |
| | $ | 2.4 |
| |
Premiums charged for insurance services provided by MVIC (a) | | | $ | 2.7 |
| | $ | 3.1 |
| | $ | 3.4 |
|
| Transactions with the Service Company: | | | | | | | | | | | | |
| Charges for services provided | | $ | 39.0 |
| | $ | 38.7 |
| | $ | 30.9 |
| | $ | 25.7 |
| | $ | 39.0 |
| | $ | 38.7 |
|
| Charges to the Service Company | | $ | 4.2 |
| | $ | 4.5 |
| | $ | 6.1 |
| | $ | 4.9 |
| | $ | 4.2 |
| | $ | 4.5 |
|
| Transactions with other AES affiliates: | | | | | | | | | | | | |
| Charges for health, welfare and benefit plans | | $ | 14.3 |
| | $ | 9.4 |
| | $ | 14.8 |
| | $ | 8.7 |
| | $ | 14.3 |
| | $ | 9.4 |
|
Charges to affiliates for non-power goods or services (c) | | $ | 3.7 |
| | $ | 5.7 |
| | $ | 4.9 |
| |
Charges to affiliates for non-power goods or services (b) | | | $ | 7.1 |
| | $ | 3.7 |
| | $ | 5.7 |
|
| Consulting services | | | $ | 2.0 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | |
| Balances with related parties: | | At December 31, 2017 | | At December 31, 2016 | | | | At December 31, 2018 | | At December 31, 2017 | | |
| Net payable to the Service Company | | $ | (3.9 | ) | | $ | (2.0 | ) | | | | $ | (4.8 | ) | | $ | (3.9 | ) | | |
Short-term loan with DPL | | $ | — |
| | $ | 5.0 |
| | | |
| Net receivable from / (payable) to other AES affiliates | | $ | 4.8 |
| | $ | (2.5 | ) | | | | $ | (0.5 | ) | | $ | 4.8 |
| | |
| |
| (a) | DP&L sold power to DPLER and MC Squared to satisfy the electric requirements of their retail customers. The revenue dollars associated with sales to DPLER and MC Squared are recorded as wholesale revenues in DP&L’s Financial Statements. These agreements were terminated on the sale of DPLER on January 1, 2016.
|
| |
(b) | MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums charged by MVIC to DP&L. |
| |
(c)(b) | In the normal course of business DP&L incurred and recorded expenses on behalf of DPL affiliates, which included DPLER.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 taxesTaxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L&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 $8.6$19.6 million and $9.5$6.5 million at December 31, 20172018 and 2016,2017, respectively, which is
recorded in Other current assetsTaxes 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 1314 – 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 ("Generation assets") 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.
The following table summarizes the carrying amounts of DP&L's Generation assets that were transferred to AES Ohio Generation on October 1, 2017:
|
| | | | |
| $ in millions | | October 1, 2017 |
| ASSETS | | |
| Restricted cash | | $ | 2.0 |
|
| Accounts receivable, net | | 31.3 |
|
| Inventories | | 42.0 |
|
| Taxes applicable to subsequent years | | 1.8 |
|
| Property, plant & equipment, net | | 87.0 |
|
| Intangible assets, net | | 0.7 |
|
| Other assets | | 15.5 |
|
| Total assets | | $ | 180.3 |
|
| | | |
| LIABILITIES | | |
| Accounts payable | | $ | 12.4 |
|
Accrued taxes (b) | | (3.9 | ) |
Long-term debt (a) | | 0.3 |
|
Deferred taxes (b) | | (91.9 | ) |
| Pension, retiree and other benefits | | 9.6 |
|
| Unamortized investment tax credit | | 15.1 |
|
| Asset retirement obligations | | 126.3 |
|
| Other liabilities | | 24.1 |
|
| Total liabilities | | $ | 92.0 |
|
| | | |
| Total accumulated other comprehensive income | | 2.1 |
|
| | | |
| Net assets transferred to AES Ohio Generation | | $ | 86.2 |
|
| |
| (a) | 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 2016 and 2015. Similarly, the assets and liabilities related to the generation business were classified as held-for-sale as of December 31, 2016.
The following table summarizes the major categories of assets and liabilities at December 31, 2016, and the revenues, cost of revenues, operating and other expenses and income tax of discontinued operations for the periods indicated:
|
| | | | | | | | | | | | |
| | | | | December 31, | | |
| $ in millions | | | | 2016 | | |
| Restricted cash | | | | $ | 29.0 |
| | |
| Accounts receivable, net | | | | 34.9 |
| | |
| Inventories | | | | 66.5 |
| | |
| Taxes applicable to subsequent years | | | | 11.3 |
| | |
| Property, plant & equipment, net | | | | 156.7 |
| | |
| Intangible assets, net | | | | 0.9 |
| | |
| Other assets | | | | 25.3 |
| | |
| Total assets of the disposal group classified as held-for-sale in the balance sheets | |
|
| | $ | 324.6 |
| | |
| | | | | | | |
| Accounts payable | | | | $ | 54.8 |
| | |
| Accrued taxes | | | | 3.5 |
| | |
| Long-term debt | | | | 13.4 |
| | |
| Taxes payable | | | | 11.3 |
| | |
Deferred taxes (a) | | | | (120.7 | ) | | |
| Pension, retiree and other benefits | | | | 8.2 |
| | |
| Unamortized investment tax credit | | | | 16.6 |
| | |
| Asset retirement obligations | | | | 127.0 |
| | |
| Other liabilities | | | | 43.6 |
| | |
| Total liabilities of the disposal group classified as held-for-sale in the balance sheets | |
|
| | $ | 157.7 |
| | |
| | | | | | | |
| | | Years ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| Revenues | | $ | 358.4 |
| | $ | 557.9 |
| | $ | 901.6 |
|
| Cost of revenues | | (191.6 | ) | | (341.1 | ) | | (698.3 | ) |
| Operating and other expenses | | (156.8 | ) | | (202.0 | ) | | (250.8 | ) |
| Fixed-asset impairment | | (66.3 | ) | | (1,353.5 | ) | | — |
|
| Loss from discontinued operations | | (56.3 | ) | | (1,338.7 | ) | | (47.5 | ) |
| Income tax benefit from discontinued operations | | (15.9 | ) | | (468.4 | ) | | (23.9 | ) |
| Net loss from discontinued operations | | $ | (40.4 | ) | | $ | (870.3 | ) | | $ | (23.6 | ) |
|
| | | | | | | | |
| | | 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 | ) |
| |
(a) | Deferred taxes represent the tax asset position netted with liabilities on DP&L prior to Generation Separation.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 $(10.4) million, $50.9$21.8 million and $138.7$29.9 million for the years ended December 31, 2017 2016 and 2015,2016, respectively. Cash flows from investing activities for discontinued operations were $23.4 million, $(50.9)$(3.5) million and $(24.3)$(39.0) million for the years ended December 31, 2017 2016 and 2015, respectively. Cash flows from financing activities for discontinued operations were $(13.0) million, $0.0 million and $(114.4) million for the years ended December 31, 2017, 2016, and 2015, 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 debt and interest expense wereis included in discontinued operations above. The interest expense included in discontinued operations was $0.2 million $0.5 million and $2.9$0.5 million for the years ended December 31, 2017 2016 and 2015,2016, respectively.
Note 1415 – Subsequent EventDispositions
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 estimates that it will recognize aggregate pre-taxrecognized a loss on disposal chargesthe transfer of approximately $12.4 million and thatmade cash expenditures of $15.0$14.5 million, in the aggregate will be made, inclusive of cash expenditures for the disposaltransfer 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, 2017,2018, 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, 2017.2018. 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, 2017.2018.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 20172018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B – Other Information
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 and DP&L estimate that they will recognize aggregate pre-tax loss on disposal charges of approximately $11.7 million and $12.4 million, respectively, and that cash expenditures of $15.0 million in the aggregate will be made, inclusive of cash expenditures for the disposal charges.None.
PART III
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, 20172018 and 2016.2017. Other than as set forth below, no professional services were rendered or fees billed by Ernst & Young LLP during the years ended December 31, 20172018 and 2016.2017.
| | | | | Fees billed | | Fees billed |
| | | Years ended December 31, | | Years ended December 31, |
| | | 2017 | | 2016 | | 2018 | | 2017 |
Audit fees (a) | | $ | 1,693,250 |
| | $ | 1,849,450 |
| | $ | 1,242,650 |
| | $ | 1,693,250 |
|
Audit-related Fees (b) | | 92,500 |
| | 112,900 |
| | 84,000 |
| | 92,500 |
|
| Tax Fees | | — |
| | — |
| | — |
| | — |
|
| All Other Fees | | — |
| | — |
| | — |
| | — |
|
| Total | | $ | 1,785,750 |
| | $ | 1,962,350 |
| | $ | 1,326,650 |
| | $ | 1,785,750 |
|
| |
| (a) | Audit fees relate to professional services rendered for the audit of our annual financial statements and the reviews of our quarterly financial statements and other services that are normally provided in connection with regulatory filing or engagements and services rendered under an agreed upon procedure engagement related to environmental studies. |
| |
| (b) | Audit-related fees relate to services rendered to us for assurance and related services. |
The Boards of Directors of DPL Inc. and The Dayton Power and Light Company (collectively, the Board) pre-approve all audit and permitted non-audit services, including engagement fees and terms for such services in accordance with Section 10A of the Securities Exchange Act of 1934, as amended. The Board will generally pre-approve a listing of specific services and categories of services, including audit, audit-related and other services, for the 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.
PART IV
Item 15 – Exhibits, Financial Statements and Financial Statement Schedules
|
| |
| The following documents are filed as part of this report: | |
| 1. Financial Statements | |
| DPL – Report of Independent Registered Public Accounting Firms | |
DPL – Consolidated Statements of Operations for each of the three years in the period ended December 31, 20172018 | |
DPL – Consolidated Statements of Other Comprehensive LossIncome / (Loss) for each of the three years in the period ended December 31, 20172018 | |
DPL – Consolidated Balance Sheets at December 31, 20172018 and 20162017 | |
DPL – Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 20172018 | |
DPL – Consolidated Statements of Shareholder’s Equity for each of the three years in the period ended December 31, 20172018 | |
| DPL – Notes to Consolidated Financial Statements | |
| DP&L – Report of Independent Registered Public Accounting Firm | |
DP&L – Statements of Operations for each of the three years in the period ended December 31, 20172018 | |
DP&L – Statements of Other Comprehensive Income / (Loss) for each of the three years in the period ended December 31, 20172018 | |
DP&L – Balance Sheets at December 31, 20172018 and 20162017 | |
DP&L – Statements of Cash Flows for each of the three years in the period ended December 31, 20172018 | |
DP&L – Statements of Shareholder’s Equity for each of the three years in the period ended December 31, 20172018 | |
| DP&L – Notes to Financial Statements | |
| | |
| 2. Financial Statement Schedules | |
Schedule II – Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172018 | |
| The information required to be submitted in Schedules I, III, IV and V is omitted as not applicable or not required under rules of Regulation S-X. |
Exhibits
DPL and DP&L exhibits are incorporated by reference as described unless otherwise filed as set forth herein.
The exhibits filed as part of DPL’s and DP&L’s Annual Report on Form 10-K, respectively, are:
|
| | | | |
| DPL | DP&L | Exhibit Number | Exhibit | Location |
| X | | 2(a) | Agreement and Plan of Merger, dated as of April 19, 2011, by and among DPL Inc., The AES Corporation and Dolphin Sub, Inc. | |
| X | X | 2(b) | Asset Purchase Agreement dated April 21, 2017, by and among Dynegy Zimmer, LLC, Dynegy Miami Fort, LLC, AES Ohio | |
| X | X | 2(c) | Asset Contribution Agreement, dated as of September 28, 2017, by and between The Dayton Power and Light Company and AES Ohio Merger Sub, LLC | |
| X | X | 2(d) | Agreement and Plan of Merger, dated as of September 28, 2017, by and between AES Ohio Merger Sub, LLC and AES Ohio Generation, LLC | |
| X | | 2(e) | 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 | |
| X | | 3(a) | Amended Articles of Incorporation of DPL Inc., as amended through January 6, 2012 | |
| X | | 3(b) | Amended Regulations of DPL Inc., as amended through November 28, 2011 | |
| | X | 3(c) | Amended Articles of Incorporation of The Dayton Power and Light Company, as of January 4, 1991 | |
| | X | 3(d) | Regulations of The Dayton Power and Light Company, as of April 9, 1981 | |
| X | X | 4(a) | Composite Indenture dated as of October 1, 1935, between The Dayton Power and Light Company and Irving Trust Company, Trustee with all amendments through the Twenty-Ninth Supplemental Indenture | |
| X | X | 4(b) | Forty-First Supplemental Indenture dated as of February 1, 1999, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
| X | X | 4(c) | Forty-Second Supplemental Indenture dated as of September 1, 2003, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
| X | X | 4(d) | Forty-Third Supplemental Indenture dated as of August 1, 2005, between The Dayton Power and Light Company and The Bank of New York, Trustee | |
| X | | 4(e) | Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, Trustee | |
| X | | 4(f) | First Supplemental Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, as Trustee | |
| X | | 4(g) | Amended and Restated Trust Agreement dated as of August 31, 2001 among DPL Inc., The Bank of New York, The Bank of New York (Delaware), the administrative trustees named therein, and several Holders as defined therein | |
|
| | | | |
DPL | DP&L | Exhibit
Number
| Exhibit | Location |
| X | X | 4(h) | Loan Agreement, dated as of September 1, 2006, by and between Ohio Air Quality Development Authority and The Dayton Power and Light Company | |
| X | | 4(i) | Indenture dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National Association | |
| X | | 4(j) | Supplemental Indenture dated as of November 28, 2011, between DPL Inc. and Wells Fargo Bank, National Association | |
| X | | 4(k) | Indenture dated October 6, 2014, between DPL Inc. and U.S. Bank National Association. | |
| X | X | 4(l) | 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 | |
| X | X | 4(m) | Loan Agreement dated August 1, 2015, between the Ohio Air Quality Development Authority and The Dayton Power and Light Company, relating to the 2015 Series B bonds | |
|
| | | | |
| DPL | DP&L | Exhibit Number | Exhibit | Location |
| X | X | 4(n) | Forty-Eighth Supplemental Indenture dated as of August 1, 2015 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company | |
| X | X | 4(o) | Forty-Ninth Supplemental Indenture dated as of August 1, 2015 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company | |
| X | X | 4(p) | 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 | |
| X | X | 4(q) | Amendment dated as of February 21, 2017 to Bond Purchase and Covenants Agreement by and among The Dayton Power and Light Company, SunTrust Bank, as Administrative Agent, and several lenders from time to time party thereto, dated as of August 1, 2015 | |
| X | X | 4(r) | Fiftieth Supplemental Indenture dated as of August 1, 2016, by and between The Dayton Power and Light Company and The Bank of New York Mellon, Trustee | |
| X | X | 4(s) | Fifty-First Supplemental Indenture between The Bank of New York Mellon, as Trustee, and The Dayton Power and Light Company | |
| X | | 10(a) | Credit Agreement dated as of July 31, 2015, among DPL Inc., U.S. Bank National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and an L/C Issuer, PNC Bank, National Association, as Syndication Agent and an L/C Issuer, Bank of America, N.A., as Documentation Agent and an L/C Issuer, and the other lenders party to the Credit Agreement | |
|
| | | | |
DPL | DP&L | Exhibit
Number
| Exhibit | Location |
| X | | 10(b) | 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 | |
| X | | 10(c) | Guaranty Agreement dated as of July 31, 2015, between DPL Energy, LLC and U.S. Bank National Association, as Administrative Agent | |
| X | | 10(d) | Pledge Agreement dated as of July 31, 2015, between DPL Inc. and U.S. Bank National Association, as Collateral Agent | |
| X | | 10(e) | 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 | |
| X | X | 10(f) | 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 | |
| X | X | 10(g) | 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 | |
| X | | 10(h) | 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 | |
| X | | 10(i) | 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 | |
|
| | | | |
| DPL | DP&L | Exhibit Number | Exhibit | Location |
| X | X | 10(j) | 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 | |
|
| | | | |
DPL | DP&L | Exhibit
Number
| Exhibit | Location |
| X | X | 10(k) | 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 | |
| X | X | 10(l) | 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 | |
| X | X | 10(m) | Stipulation and Recommendation dated January 30, 2017 | |
| X | X | 10(n) | Amended Stipulation and Recommendation dated March 13, 2017 | |
| X | | 31(a) | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| X | | 31(b) | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| | X | 31(c) | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| | X | 31(d) | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| X | | 32(a) | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| X | | 32(b) | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| | X | 32(c) | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| | X | 32(d) | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| X | X | 101.INS | XBRL Instance | Furnished herewith as Exhibit 101.INS |
| X | X | 101.SCH | XBRL Taxonomy Extension Schema | Furnished herewith as Exhibit 101.SCH |
| X | X | 101.CAL | XBRL Taxonomy Extension Calculation Linkbase | Furnished herewith as Exhibit 101.CAL |
| X | X | 101.DEF | XBRL Taxonomy Extension Definition Linkbase | Furnished herewith as Exhibit 101.DEF |
| X | X | 101.LAB | XBRL Taxonomy Extension Label Linkbase | Furnished herewith as Exhibit 101.LAB |
| X | X | 101.PRE | XBRL Taxonomy Extension Presentation Linkbase | Furnished herewith as Exhibit 101.PRE |
Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.
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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.
|
| |
| | DPL Inc. |
| | |
| | |
| | |
February 26, 20182019 | /s/ KennethBarry J. ZagzebskiBentley |
| | KennethBarry J. ZagzebskiBentley |
| | Interim President and Chief Executive Officer |
| | (principal executive officer) |
| | |
| | |
| | The Dayton Power and Light Company |
| | |
| | |
| | |
February 26, 20182019 | /s/ Thomas A. RagaBarry J. Bentley |
| | Thomas A. RagaBarry J. Bentley |
| | Interim President and Chief Executive Officer |
| | (principal executive officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of DPL Inc. and in the capacities and on the dates indicated.
|
| | | |
/s/ Craig L. JacksonKenneth J. Zagzebski | | Director and Chief Financial OfficerChairman | February 26, 20182019 |
Craig L. Jackson | | (principal financial officer) | |
| | | |
| | | |
/s/ BarryKenneth J. Bentley | | Director | February 26, 2018 |
Barry J. BentleyZagzebski | | | |
| | | | |
| | | | |
| /s/ Leonardo Moreno | | Director | February 26, 20182019 |
| Leonardo Moreno | | | |
| | | | |
| | | | |
| /s/ Mary Stawikey | | Director | February 26, 20182019 |
| Mary Stawikey | | | |
| | | | |
| | | | |
/s/ KennethBarry J. ZagzebskiBentley | | Director and Interim President and Chief Executive Officer | February 26, 20182019 |
KennethBarry J. ZagzebskiBentley | | (principal executive officer) | |
| | | | |
| | | | |
/s/ Kurt A. TornquistGustavo Garavaglia | | Chief Financial Officer | February 26, 2019 |
| Gustavo Garavaglia | | (principal financial officer) | |
| | | |
| | | |
| /s/ Karin M. Nyhuis | | Controller | February 26, 20182019 |
Kurt A. TornquistKarin M. Nyhuis | | (principal accounting officer) | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of The Dayton Power and Light Company and in the capacities and on the dates indicated.
|
| | | |
/s/ Brian A. MillerKenneth J. Zagzebski | | Director and Chairman | February 26, 2018 |
Brian A. Miller | | | |
| | | |
| | | |
/s/ Kenneth J. Zagzebski | | Director | February 26, 20182019 |
| Kenneth J. Zagzebski | | | |
| | | | |
| | | | |
/s/ Barry J. BentleyJulian Nebreda | | Director | February 26, 20182019 |
Barry J. BentleyJulian Nebreda | | | |
| | | | |
| | | | |
| /s/ Leonardo Moreno | | Director | February 26, 20182019 |
| Leonardo Moreno | | | |
| | | | |
| | | | |
| /s/ Mark E. Miller | | Director | February 26, 20182019 |
| Mark E. Miller | | | |
| | | | |
| | | | |
| /s/ Paul L. Freedman | | Director | February 26, 20182019 |
| Paul L. Freedman | | | |
| | | | |
| | | | |
| /s/ Tish D. Mendoza | | Director | February 26, 20182019 |
| Tish D. Mendoza | | | |
| | | | |
| | | | |
| /s/ Thomas A. Raga | | Director | February 26, 2019 |
| Thomas A. Raga | | | |
| | | |
| | | |
| /s/ Barry J. Bentley | | Director and Interim President and Chief Executive Officer | February 26, 20182019 |
Thomas A. RagaBarry J. Bentley | | (principal executive officer) | |
| | | | |
| | | | |
/s/ Craig L. JacksonGustavo Garavaglia | | Director, Vice President and Chief Financial Officer | February 26, 20182019 |
Craig L. JacksonGustavo Garavaglia | | (principal financial officer) | |
| | | | |
| | | | |
/s/ Kurt A. TornquistKarin M. Nyhuis | | Controller | February 26, 20182019 |
Kurt A. TornquistKarin M. Nyhuis | | (principal accounting officer) | |
Schedule II
| | DPL Inc. | VALUATION AND QUALIFYING ACCOUNTS | | For each of the three years ended December 31, 2017 | |
| For each of the three years ended December 31, 2018 | | For each of the three years ended December 31, 2018 |
$ in thousands | | Description | | Balance at Beginning of Period | | Additions | | Deductions (a) | | Balance at End of Period | | Balance at Beginning of Period | | Additions | | Deductions (a) | | Balance at End of Period |
| Year ended December 31, 2018 | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | |
| Provision for uncollectible accounts | | | $ | 1,053 |
| | $ | 3,411 |
| | $ | 3,574 |
| | $ | 890 |
|
| Deducted from deferred tax assets - | | | | | | | | | |
Valuation allowance for deferred tax assets (b) | | | $ | 36,328 |
| | $ | 1,539 |
| | $ | 8,794 |
| | $ | 29,073 |
|
| Year ended December 31, 2017 | | | | | | | | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | | | | | | | | |
Provision for uncollectible accounts (b) | | $ | 1,159 |
| | $ | 3,141 |
| | $ | 3,247 |
| | $ | 1,053 |
| | $ | 1,159 |
| | $ | 3,141 |
| | $ | 3,247 |
| | $ | 1,053 |
|
| Deducted from deferred tax assets - | | | | | | | | | | | | | | | | |
| Valuation allowance for deferred tax assets | | $ | 38,266 |
| | $ | 4,383 |
| | $ | 6,321 |
| | $ | 36,328 |
| |
Valuation allowance for deferred tax assets | | | $ | 38,266 |
| | $ | 4,383 |
| | $ | 6,321 |
| | $ | 36,328 |
|
| Year ended December 31, 2016 | | | | | | | | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | | | | | | | | |
Provision for uncollectible accounts (b) | | $ | 835 |
| | $ | 4,113 |
| | $ | 3,789 |
| | $ | 1,159 |
| |
| Provision for uncollectible accounts | | | $ | 835 |
| | $ | 4,113 |
| | $ | 3,789 |
| | $ | 1,159 |
|
| Deducted from deferred tax assets - | | | | | | | | | | | | | | | | |
Valuation allowance for deferred tax assets | | $ | 39,874 |
| | $ | — |
| | $ | 1,608 |
| | $ | 38,266 |
| | $ | 39,874 |
| | $ | — |
| | $ | 1,608 |
| | $ | 38,266 |
|
| Year ended December 31, 2015 | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | |
Provision for uncollectible accounts (b) | | $ | 898 |
| | $ | 3,766 |
| | $ | 3,829 |
| | $ | 835 |
| |
| Deducted from deferred tax assets - | | | | | | | | | |
| Valuation allowance for deferred tax assets | | $ | 40,713 |
| | $ | 3,501 |
| | $ | 4,340 |
| | $ | 39,874 |
| |
(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. |
|
| | | | | | | |
| (a) | Amounts written off, net of recoveries of accounts previously written off | |
| (b) | Provision for uncollectible accounts related to DPL's held-for-sale business as detailed below were excluded from the table above and were included in "Assets held-for-sale - current" in the Consolidated Balance Sheets. | |
| | | For the year ended, December 31, 2015 | | | |
| | Beginning balance | $ | 369 |
| |
| |
| | Additions | 2,035 |
| |
| |
| | Deductions | 2,291 |
| |
| |
| | Ending balance | $ | 113 |
| |
| |
| | THE DAYTON POWER AND LIGHT COMPANY | VALUATION AND QUALIFYING ACCOUNTS | | For each of the three years ended December 31, 2017 | |
| For each of the three years ended December 31, 2018 | | For each of the three years ended December 31, 2018 |
$ in thousands | | Description | | Balance at Beginning of Period | | Additions | | Deductions (a) | | Balance at End of Period | | Balance at Beginning of Period | | Additions | | Deductions (a) | | Balance at End of Period |
| Year ended December 31, 2018 | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | |
| Provision for uncollectible accounts | | | $ | 1,053 |
| | $ | 3,411 |
| | $ | 3,574 |
| | $ | 890 |
|
| Year ended December 31, 2017 | | | | | | | | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | | | | | | | | |
| Provision for uncollectible accounts | | $ | 1,159 |
| | $ | 3,141 |
| | $ | 3,247 |
| | $ | 1,053 |
| | $ | 1,159 |
| | $ | 3,141 |
| | $ | 3,247 |
| | $ | 1,053 |
|
| Year ended December 31, 2016 | | | | | | | | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | | | | | | | | |
| Provision for uncollectible accounts | | $ | 835 |
| | $ | 4,113 |
| | $ | 3,789 |
| | $ | 1,159 |
| | $ | 835 |
| | $ | 4,113 |
| | $ | 3,789 |
| | $ | 1,159 |
|
| Year ended December 31, 2015 | | | | | | | | | |
| Deducted from accounts receivable - | | | | | | | | | |
| Provision for uncollectible accounts | | $ | 897 |
| | $ | 3,766 |
| | $ | 3,828 |
| | $ | 835 |
| |
(a) Amounts written off, net of recoveries of accounts previously written off