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.
Substantially all property and stations of DP&L are subject to the lien of the First and Refunding Mortgage.
Item 3
Item 3 - Legal Proceedings
DPL and DP&L are involved in certain claims, suits and legal proceedings in the normal course of business. DPL and DP&L have accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. DPL and DP&L believe, based upon information they currently possess and taking into account established reserves for estimated liabilities and insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on their financial statements. It is reasonably possible, however, that some matters could be decided unfavorably and could require DPL or DP&L to pay damages or make expenditures in amounts that could be material but cannot be estimated as of December 31, 2015.
In February 2007, DP&L filed a lawsuit in the United States District Court for Southern District of Ohio against Appalachian Fuels, LLC (Appalachian) seeking damages incurred due to Appalachian’s failure to supply approximately 1.5 million tons of coal to two commonly-owned stations under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. Appalachian has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.
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
Item 4 - Mine Safety Disclosures
Not applicable.
PART II
Item 5
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, and has been owned throughout all of 2015, 2014 and 2013, indirectly by AES and directly by an AES wholly-owned subsidiary. As a result, our stock is not listed for trading on any stock exchange. DP&L’s common stock is held solely by DPL and, as a result, is not listed for trading on any stock exchange.
Dividends
During the years ended December 31, 2015, 2014 and 2013, DPL paid no dividends to AES. During the year ended December 31, 2013, DPL’s Board of Directors amended the prior 2012 dividend declaration of $70.0 million
to be equal to the amount paid, $64.1 million, reversing $5.9 million of the 2012 dividend. DP&L declares and pays dividends on its common shares to its parent DPL from time to time as declared by the DP&L board. Dividends on common shares in the amount of $50.0 million, $159.0 million and $190.0 million were declared and paid in the years ended December 31, 2015, 2014 and 2013, respectively. DP&L declared and paid dividends on preferred shares in the amount of $0.9 million in each of the years ended December 31, 2015, 2014 and 2013.
As of December 31, 2015, DPL’s leverage ratio was at 1.03 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015, DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).
DPL’s secured revolving credit agreement, secured term loan and senior unsecured notes due 2019 include provisions substantially similar to DPL's Articles of Incorporation. As a result, as of December 31, 2015, DPL was also prohibited under each of these documents from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).
As long as DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation contain provisions which could limit the payment of cash dividends on any of its common stock. Please see Note 10 - Equity of Notes to DP&L's Consolidated Financial Statements.
Item 6
Item 6 - Selected Financial Data
The following table presents our selected consolidated financial data which should be read in conjunction with our audited Consolidated Financial Statements and the related Notes thereto and Item 7
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. Please see “Forward-Looking Statements” at the beginning of this Form 10-K and Item 1A - Risk Factors. For a list of certain abbreviations or acronyms in this discussion, see Glossary of Terms at the beginning of this Form 10-K.
BUSINESS OVERVIEW
DPL is a regional electric energy and utility company. DPL previously had two reporting segments which were the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. DPLER had a subsidiary, MC Squared that was sold on April 1, 2015. On December 28, 2015, an agreement was signed to sell DPLER. As of December 31, 2015, DPLER met the criteria to be recorded as a Discontinued Operation. As a result, DPL now has one reportable segment. See Note 14 - Business Segments of Notes to DPL’s Consolidated Financial Statements for more information relating to our reportable segment and
Note 16 - Discontinued Operations of Notes to DPL’s Consolidated Financial Statements. DP&L does not have any reportable segments. DPL is a wholly-owned subsidiary of AES.
DP&L is primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio and, prior to its sale in January 2016, the sale of energy to DPLER in Ohio and Illinois. DPL and DP&L strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, DPL’s and DP&L’s strategy is to match energy supply with load or customer demand, maximizing profits while effectively managing exposure to movements in energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost while maintaining the highest level of customer service and reliability.
We operate and manage generation assets and are exposed to a number of risks. These risks include, but are not limited to, electricity wholesale price risk, PJM capacity price risk, regulatory risk, environmental risk, fuel supply and price risk and the risk associated with electric generating station performance. We attempt to manage these risks through various means. For instance, we operate a portfolio of wholly-owned and jointly-owned generation assets that is diversified as to coal source, cost structure and operating characteristics. We are focused on the operating efficiency of these stations and maintaining their availability.
We operate and manage transmission and distribution assets in a rate-regulated environment. Accordingly, this subjects us to regulatory risk in terms of the costs that we may recover and the investment returns that we may collect in customer rates. We are focused on delivering electricity and maintaining high standards of customer service and reliability in a cost-effective manner.
Additional information relating to our risks is contained in Item 1A - Risk Factors.
The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related footnotes included in Item 8 - Financial Statements and Supplementary Data.
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.
DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of regulatory oversight as well as environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated.
Retail Rate Regulation
Ohio law allows retail customers to choose their electric generation supplier and requires an electric distribution utility to provide SSO for any customer that does not choose an alternative generation supplier. The generation and market-based transmission of SSO service is procured through a layering of competitive bid auctions whereby winning bidders are awarded the right and contractual obligation to supply generation service to a portion of the SSO within the utility’s service territory over a certain period of time (generally one, two or three years). Winning bidders are awarded a number of tranches (each tranche is equal to 1% of SSO load) based on the lowest bid price in a reverse clock auction. The PUCO oversees the competitive bid and must certify the results each time the bid process is complete.
DP&L’s SSO price is set based on the blended combination of the results of the competitive bid auctions, and thus reflects wholesale market prices. DP&L bills and collects competitive bid rates from SSO customers and pays the winning bidders based on actual energy supplied. Beginning January 1, 2016, DP&L’s SSO price will be set based on 100% competitive bid results. Notwithstanding impacts to DP&L’s wholesale activities, market prices will have less of a direct impact on DP&L retail margins in the future since any decrease in market price will result in a decrease of SSO revenues and an offsetting decrease of costs of providing SSO service.
Ohio law allows for pass through of certain costs to retail customers. For example, compliance costs associated with the renewable and energy efficiency laws are recovered through separate riders, or trackers, and are reset on
an annual basis. Other costs such as the non-market based transmission and ancillary costs are also passed through in the form of an annual tracker. Costs recovered through a tracker are deferred and carrying costs are applied to any over or under recovered balances. Costs associated with excise tax, low income programs, economic development, storm costs, and other costs may be recovered through a tracker that is trued-up on an annual or periodic basis. The PUCO reviews, audits and must authorize all rate tracker rate changes prior to implementation.
Ohio distribution utilities are permitted to file distribution rate case applications in accordance with the rate making provisions of the Ohio Revised Code and Ohio Administrative Code. DP&L filed a distribution rate case on November 30, 2015. See Item 1 - Business - Competition and Regulation for further details.
The costs associated with providing high voltage transmission service and wholesale electric sales and ancillary services are subject to FERC jurisdiction. While DP&L has market-based rate authority for wholesale electric sales, DP&L would be required to file an application at FERC under section 101 of Title 18 of the Code of Federal Regulations to change any of its cost-based transmission or ancillary service rates.
As directed by the PUCO, DP&L filed a corporate separation plan in December 2013 stating its plan to transfer or sell its generation assets. In July 2014, DP&L publicly announced its decision not to sell DP&L’s generation assets at this time, but to maintain its plans to transfer or sell the assets in accordance with PUCO orders by January 1, 2017. The PUCO approved DP&L’s plan to separate its generation assets with minor modifications.
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 SSO to 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.
Lower market prices for power resulted in increased levels of competition to provide retail generation services. This in turn led to CRES providers, including DPLER, having approximately 72% of 2015 total electric sales in DP&L’s service territory. DPLER, an affiliated company and one of the registered CRES providers marketing generation services to DP&L customers, was sold on January 1, 2016. As discussed in Item 1, beginning January 1, 2016, customer switching will have no effect on DP&L’s margins. See Item 1A - Risk Factors for more information.
The following table provides a summary of the number of electric customers and volumes provided by all CRES providers in our service territory during the years ended December 31, 2015, 2014 and 2013:
(a)
The kWh sales include all distribution sales, including those whose power is supplied by DPLER and non-affiliated CRES providers.
FUEL AND RELATED COSTS
Fuel and Commodity Prices
The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues are
affecting mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. We have substantially all of the total expected coal volume needed to meet our wholesale sales requirements for 2016 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 controls 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 2016. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.
FINANCIAL OVERVIEW
The results of operations of both DPL and DP&L are separately discussed in more detail in the following pages.
The following table summarizes the significant components of DPL’s Results of Operations for the years ended December 31, 2015, 2014 and 2013:
(a)
For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
RESULTS OF OPERATIONS - DPL Inc.
DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this report.
Income Statement Highlights - DPL
(a)
For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
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
(a)
Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees. In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 65 degrees Fahrenheit.
Since we have historically utilized our internal generating capacity to supply the needs of our retail customers within the DP&L service territory first, increases in on-system retail demand may have decreased the volume of internal generation available to be sold in the wholesale market and vice versa. Beginning in 2016, DP&L retail demand is sourced 100% through a competitive auction. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors affecting our wholesale sales volume each hour of the year include: wholesale market prices; our retail demand; retail demand elsewhere throughout the entire wholesale market area; our stations’ and other utility stations’ availability to sell into the wholesale market; and weather conditions across the multi-state region. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities or when margin opportunities exist between the wholesale sales and power purchase prices.
The following table provides a summary of changes in revenues from prior periods:
During the year ended December 31, 2015, Revenues decreased $103.7 million, or 6%, to $1,612.8 million from $1,716.5 million in the same period of the prior year. This decrease was primarily the result of lower wholesale sales, lower average retail rates and lower retail volume, partially offset by increased RTO capacity and other revenues.
•
Retail revenues decreased $47.3 million primarily due to lower retail prices driven by decreased retail revenue for SSO customers as the competitive auction rate, which represents 60% of DP&L SSO load in 2015 as compared to 10% in 2014, is lower than our non-auction generation rate, a decrease in the USF program recovery rate in 2015, and higher recovery of transmission costs in the prior year. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015. Sales volume also decreased due to milder winter weather in 2015. The aforementioned impacts resulted in an unfavorable $28.7 million retail price variance and an unfavorable $13.0 million retail volume variance.
•
Wholesale revenues decreased $86.8 million primarily as a result of an unfavorable $90.9 million wholesale volume variance and a favorable $4.1 million wholesale price variance. Although DP&L had excess generation available to be sold in the wholesale market in 2015 resulting from 60% of its SSO load being
served through the competitive bid process compared to 10% during 2014, there was also a 17% decrease in net generation from DP&L's co-owned and operated plants due to the 2014 sale of East Bend, the closing of Beckjord and increased outages. DPL also had decreased full requirements sales to DPLER, as a result of the sale of MC Squared and decreased customers at DPLER in 2015 compared to 2014. These sales were previously eliminated in consolidation prior to DPLER becoming a discontinued operation. The price increase of $4.1 million was due to higher prices on sales to DPLER, partially offset by lower market prices.
•
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $30.7 million compared to the prior year. This increase was primarily the result of a $42.5 million increase in revenue realized from the PJM capacity auction. The capacity prices that became effective in June of 2015 were $136/MW/day, compared to $126/MW/day in June 2014 and $28/MW/day in June 2013. This increase was offset by an $11.8 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.
During the year ended December 31, 2014, Revenues increased $137.5 million, or 9%, to $1,716.5 million from $1,579.0 million in the same period of the prior year. This increase was primarily the result of higher average retail rates and increased RTO capacity revenues; partially offset by lower retail and wholesale sales volume.
•
Retail revenues increased $52.4 million primarily due to a 9.5% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various costs through regulatory riders. DP&L sales volume also decreased by 7.4% from the prior year due to customer switching. The above resulted in a favorable $108.4 million retail price variance and an unfavorable $55.7 million retail volume variance.
•
Wholesale revenues only increased $1.3 million, or 0.2%, due to an $11.3 million favorable wholesale price variance, partially offset by a $10.0 million unfavorable wholesale volume variance. Although customer switching in the DP&L service territory resulted in increased generation available to sell in the wholesale market, there was a 13% decrease in net generation available from DP&L’s co-owned and operated generation plants due to higher outages which resulted in the decrease in wholesale sales volume. The price increase of $11.3 million was due to higher prices on sales to DPLER, partially offset by lower market prices.
•
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $83.2 million. This increase was primarily a result of a $79.2 million increase in revenues realized from the PJM capacity auction and an increase of $4.0 million in RTO transmission and congestion revenues.
DPL - Cost of Revenues
During the year ended December 31, 2015, Total cost of revenues decreased $70.0 million, or 8% compared to the prior year. This decrease was a result of:
•
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $44.7 million, or 15%, compared to the prior year primarily due to a 16% decrease in internal generation as a result of increased outages and plant closures or sales, partially offset by a 2.4% increase in average fuel cost per MWh.
•
Net purchased power decreased $25.3 million, or 4%, compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power increased $12.4 million, or 4%, primarily due to a $23.9 million increase as a result of a 6.5% increase in average purchased power price, and also due to increased purchases for our SSO load through the competitive bid process. These increases were partially offset by an $11.5 million volume decrease driven by decreased power purchased to source DPLER customers throughout 2015 due to the sale of MC Squared along with customer switching. The price increase above also includes a partial offset resulting from a $10 million regulatory deferral of OVEC costs that are probable for future recovery. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.
◦
RTO charges decreased $56.3 million, or 37%, as a result of higher transmission and congestion charges incurred in 2014 as well as decreased load obligations as a result of increased SSO sales being sourced through the competitive auction. RTO charges are incurred as a member of PJM and include costs associated with DP&L’s load obligations.
◦
RTO capacity charges increased $15.0 million, or 14%, driven by a $7.3 million PJM penalty associated with low plant availability in 2015 compared to an approximate $2.4 million penalty recorded in 2014 and higher RTO capacity prices, partially offset by decreased load obligations for retail customers in 2015. As noted above, RTO capacity prices are set by an annual auction.
◦
Mark-to-market losses increased $3.6 million.
During the year ended December 31, 2014, Total cost of revenues increased $142.7 million, or 19% compared to the prior year. This increase was a result of:
•
Net fuel costs decreased $62.2 million, or 17%, compared to the prior year, primarily due to a 13% decrease in internal generation as a result of increased outages combined with lower average fuel prices.
•
Net purchased power increased $204.9 million, or 53%, compared to the prior year. This increase was driven by the following factors:
◦
Purchased power increased $87.2 million, or 37%, due to increased volume of $58.6 million and $28.6 million due to higher average market prices for purchased power. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.
◦
RTO charges increased $42.3 million, or 38%, as a result of higher transmission and congestion charges incurred in 2014 due to extreme weather. RTO charges are incurred as a member of PJM and include costs associated with DP&L’s load obligations for retail customers.
◦
RTO capacity charges increased $73.5 million due to higher RTO capacity prices. RTO capacity prices are set by an annual auction.
◦
Mark-to-market losses increased $1.9 million.
DPL - Operation and Maintenance
(a)
There is a corresponding increase / (decrease) in Revenues associated with these programs resulting in no impact to Net income.
During the year ended December 31, 2015, Operation and maintenance expense decreased $1.1 million compared to the prior year. This variance was primarily the result of:
•
decreased expenses for the low-income payment program which are funded by the USF revenue rate rider.
These decreases were partially offset by:
•
increased storm costs, which were previously deferred but were recognized as they were recovered through customer rates in 2015; and
•
increased expenses related to alternative energy and energy efficiency programs.
(a)
There is a corresponding increase in Revenues associated with this program resulting in no impact to Net income.
During the year ended December 31, 2014, Operation and maintenance expense decreased $3.3 million, or 1%, compared to the prior year. This variance was primarily the result of:
•
decreased expenses for the low-income payment program which are funded by the USF revenue rate rider;
•
decreased health insurance due to cost decreases as well as a reduction in the disability reserve as a result of the 2014 actuarial study; and
•
decreased deferred compensation costs.
These decreases were partially offset by:
•
increased maintenance expenses at our generation facilities;
•
increased expenses related to the maintenance of overhead transmission and distribution lines; and
•
increased expenses related to alternative energy and energy efficiency programs.
DPL - Depreciation and Amortization
During the year ended December 31, 2015, Depreciation and amortization expense decreased $1.0 million, or 1%, compared to the prior year. The decrease is primarily due to the sale of East Bend and the retirement of Beckjord, partially offset by increased depreciation associated with increased ARO assets and net plant additions.
During the year ended December 31, 2014, Depreciation and amortization expense increased $6.4 million, or 5%, compared to the prior year. The increase primarily reflects additional investments in fixed assets.
DPL - General Taxes
During the year ended December 31, 2015, General taxes changed an immaterial amount compared to the prior year.
During the year ended December 31, 2014, General taxes increased $11.0 million, or 14%, compared to the prior year. This increase was primarily due to an adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments that were made in 2014, higher property tax accruals for 2014 compared to 2013 and a favorable determination of $1.6 million from the Ohio gross receipts appeal in 2013.
DPL - Goodwill Impairment
During the year ended December 31, 2015, DPL recorded an impairment of goodwill of $317.0 million compared to $0.0 million the prior year. Our 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 and Other Intangible Assets of Notes to DPL’s Consolidated Financial Statements.
The goodwill impairment in 2014 has been reclassified to Discontinued operations. See Note 16 - Discontinued Operations of Notes to DPL’s Consolidated Financial Statements
DPL - Fixed Asset Impairment
During the year ended December 31, 2014, DPL recorded an impairment of fixed-assets of $11.5 million related to DP&L's East Bend facility, which was sold in 2014. See Note 15 - Fixed-asset Impairment of Notes to DPL's Consolidated financial Statements.
DPL - Interest Expense
During the year ended December 31, 2015, Interest expense decreased $8.3 million, or 7%, compared to the prior year due primarily to a reduction of debt at DP&L and DPL, as well as decreased interest rates on DP&L’s senior secured pollution control bonds, partially offset by increased carrying costs on regulatory assets.
During the year ended December 31, 2014, Interest expense increased $2.6 million, or 2%, compared to the prior year due primarily to reduced amortization of debt premium (which increases interest expense) partially offset by
decreased interest due to reductions in debt at DPL and decreased full year effective interest rates on DP&L’s senior secured first mortgage bonds.
DPL - Income Tax Expense
During the year ended December 31, 2015, Income tax expense increased $4.6 million compared to the prior year primarily due to higher pre-tax income (excluding the effect of the 2015 goodwill impairment). This increase was partially offset by an anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return, a deferred tax adjustment related to the expiration of the statute of limitations in 2014 that did not occur in 2015 and an increase in the tax benefits of Internal Revenue Code Section 199 in 2015.
During the year ended December 31, 2014, Income tax expense decreased $4.4 million compared to the prior year primarily due to lower pre-tax income (excluding the effect of the 2013 goodwill impairment), a 2014 deferred tax adjustment related to the expiration of the statute of limitations on the 2010 tax year and a decrease in the tax benefits of Internal Revenue Code Section 199 in 2014.
Discontinued Operations
Total discontinued operations included net income of $12.4 million, net loss of $131.8 million, and net income of $3.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 16 - Discontinued Operations in Notes to DPL's Consolidated Financial Statements.
RESULTS OF OPERATIONS - Utility Segment (DP&L)
Income Statement Highlights - DP&L
(a)
For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
DP&L - Revenues
The following table provides a summary of changes in DP&L’s Revenues from prior periods:
During the year ended December 31, 2015, Revenues decreased $116.0 million, or 7%, to $1,552.3 million from $1,668.3 million in the prior year. This decrease was primarily the result of lower retail rates and volume, and lower wholesales volume; partially offset by higher RTO capacity and other revenues.
•
Retail revenues decreased $47.5 million primarily due to lower retail prices driven by decreased retail revenue for SSO customers as the competitive auction rate, which represents 60% of our SSO load in 2015 as compared to 10% in 2014, is lower than our non-auction generation rate, a decrease in the USF program recovery rate in 2015, and higher recovery of transmission costs in the prior year. These decreases were partially offset by a price increase driven by recovery of deferred storm costs in 2015. Further, heating degree days decreased by 787, or 13%, while cooling degree days increased by 83, or 8.5%, compared to 2014, which contributed to a volume decrease. The above resulted in an unfavorable $28.7 million retail price variance and an unfavorable $13.0 million retail volume variance.
•
Wholesale revenues decreased $89.8 million as a result of an unfavorable $95.6 million wholesale volume variance and a favorable $5.8 million wholesale price variance. Although DP&L had excess generation available to be sold in the wholesale market in 2015 resulting from 60% of its SSO load being served through the competitive bid process compared to 10% during 2014, there was a 17% decrease in net generation from DP&L's co-owned and operated plants due to the 2014 sale of East Bend, the closing of Beckjord and increased unplanned outages. DP&L also had decreased full requirements sales to DPLER, as a result of the sale of MC Squared and decreased customers at DPLER in 2015 compared to 2014. The price increase was due to higher prices on sales to DPLER, partially offset by lower market prices.
•
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L's transmission assets, regulation services, reactive supply and operating reserves, as well as capacity revenues under the RPM construct, increased $21.2 million. This increase was primarily the result of a $33.1 million increase in revenue realized from the PJM capacity auction. The capacity prices that became effective in June of 2015 were $136/MW/day, compared to $126/MW/day in June 2014 and $28/MW/day in June 2013. This increase was offset by an $11.9 million decrease in RTO transmission and congestion revenue, as 2014 congestion revenue charges were higher due to extreme weather.
During the year ended December 31, 2014, Revenues increased $116.8 million, or 8%, to $1,668.3 million from $1,551.5 million in the prior year. This increase was primarily the result of higher average retail rates and increased RTO capacity revenues; partially offset by lower retail and wholesale volume.
•
Retail revenues increased $52.2 million due to a 15% increase in average retail rates which resulted from the PUCO approved service stability rider and recovery of various costs through regulatory riders. Retail volume decreased 7.4% overall due to a 26% increase in the percentage of volume in the DP&L service territory being supplied by the third-party CRES providers. DP&L continues to provide distribution services
to these customers but volumes are not recorded. Heating degree days increased by 408, or 7%, while cooling degree days decreased by 85, or 8%, compared to 2013. During 2014, 31% of DP&L's distribution sales were supplied by third-party CRES providers. As we only have distribution revenue on these sales, the weather impact is less than the weather impact on SSO sales. The above resulted in a favorable $108.4 million retail price variance and an unfavorable $55.7 million retail volume variance
•
Wholesale revenues decreased $5.3 million as a result of an $11.9 million decrease in wholesale sales volume, partially offset by a favorable $6.6 million price variance. Although customer switching in the DP&L service territory resulted in increased generation available to sell in the wholesale market, there was a 13% decrease in net generation available from DP&L's co-owned and operated generation plants due to higher outages which resulted in an overall decrease in wholesale sales volume.
•
RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $69.6 million. This increase was primarily the result of a $66.5 million increase in revenues realized from the PJM capacity market auction and an increase of $3.1 million in RTO transmission and congestion revenues.
DP&L - Cost of Revenues
During the year ended December 31, 2015 total cost of revenues decreased $96.9 million, or 11%, compared to the prior year. This decrease was primarily due to:
•
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $70.2 million, or 22%, driven by a 17% decrease in internal generation at our plants combined with lower average fuel prices.
•
Net purchased power decreased $26.7 million, or 5%, compared to the prior year. This decrease was driven by the following factors:
◦
Purchased power increased $13.6 million, or 4%, primarily due to a $24.3 million price increase, partially offset by a $10.7 million volume decrease. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand. The increase above includes a partial offset resulting from a $10 million regulatory deferral of OVEC costs that are probable for future recovery.
◦
RTO charges decreased $56.3 million, or 37%, as a result of higher transmission and congestion charges incurred in 2014 due to severe weather and decreased load obligations is 2015. RTO charges are incurred as a member of PJM and include costs associated with DP&L’s load obligations for retail customers.
◦
RTO capacity and other costs increased $12.4 million, or 12%, driven by a $7.3 million PJM penalty associated with low plant availability in 2015 and higher RTO capacity prices, partially offset by decreased load obligations for retail customers in 2015. As noted above, RTO capacity prices are set by an annual auction.
◦
Mark-to-market losses increased $3.6 million.
During the year ended December 31, 2014 total cost of revenues increased $152.9 million, or 21%, compared to the prior year. This increase was primarily due to:
•
Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $47.6 million, or 13% primarily due to a 13% decrease in internal generation due to increased outages combined with lower average fuel prices, partially offset by costs associated with the early termination of a fuel contract.
•
Net purchased power increased $200.5 million, or 53% compared to the prior year. This increase was driven by the following factors:
◦
Purchased power costs increased $85.3 million, primarily due to a volume increase of 21% as a result of increased outages at our generating stations during 2014 and average purchased power prices increased 12%. We purchase power for our SSO load sourced through the competitive bid process and to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages, when market prices are below the marginal costs associated with our generating facilities, or to meet high customer demand.
◦
RTO charges increased $40.6 million, or 37%, as a result of higher transmission and congestion charges incurred in 2014 due to severe weather. RTO charges are incurred as a member of PJM and include costs associated with DP&L’s load obligations for retail customers.
◦
RTO capacity and other costs increased $72.8 million driven by higher RTO capacity prices. As noted above, RTO capacity prices are set by an annual auction.
◦
Mark-to-market losses increased $1.8 million.
DP&L - Operation and Maintenance
(a)
There is a corresponding increase / (decrease) in Revenues associated with these programs resulting in no impact to Net income.
During the year ended December 31, 2015, Operation and maintenance expense decreased $4.7 million, or 1%, compared to the prior year. This variance was primarily the result of:
•
decreased expenses for the low-income payment program which is funded by the USF revenue rate rider; and
•
decreased maintenance expenses at our generating facilities.
These decreases were partially offset by:
•
increased storm costs, which were previously deferred but were recognized as they were recovered through customer rates in 2015; and
•
increased expenses related to alternative energy and energy efficiency programs.
(a)
There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income.
During the year ended December 31, 2014, Operation and maintenance expense decreased $9.0 million, or 2%, compared to the prior year. This variance was primarily the result of:
•
decreased expenses for the low-income payment program which is funded by the USF revenue rate rider;
•
decreased health insurance due to cost decreases as well as a reduction in the disability reserve as a result of the 2014 actuarial study;
•
lower pension expenses primarily related to changes in plan assumptions, specifically a higher discount rate; and
•
decreased deferred compensation costs.
These decreases were partially offset by:
•
increased maintenance expenses at our generating facilities;
•
increased expenses related to the maintenance of overhead transmission and distribution lines; and
•
increased expenses relating to alternative energy and energy efficiency programs.
DP&L - Depreciation and Amortization
During the year ended December 31, 2015, Depreciation and amortization expense decreased $6.6 million, or 5%, compared to the prior year. The decrease is primarily due to the sale of the East Bend Plant and the retirement of the Beckjord Plant, partially offset by increased depreciation associated with increased ARO assets and net plant additions.
During the year ended December 31, 2014, Depreciation and amortization expense increased $4.6 million, or 3%, compared to the prior year. The increase primarily reflects additional investments in fixed assets.
DP&L - General Taxes
During the year ended December 31, 2015, General taxes changed an immaterial amount compared to the prior year.
During the year ended December 31, 2014, General taxes increased $11.4 million, or 15%, compared to the prior year. This increase was primarily due to an adjustment to the 2013 estimated property tax liability to adjust estimates to actual payments that were made in 2014, higher property tax accruals for 2014 compared to 2013 and a favorable determination of $1.6 million from the Ohio gross receipts tax appeal in 2013.
DP&L - Fixed-asset Impairment and gain on asset sale
During the year ended December 31, 2015, DP&L did not have any fixed-asset impairment or significant gains on asset sales.
During the year ended December 31, 2014, DP&L recorded a gain of $4.5 million on the sale of its interest in the East Bend generating station. See Note 13 - Fixed-asset Impairment of Notes to DP&L’s Financial Statements for more information on the impairment.
DP&L - Interest Expense
During the year ended December 31, 2015, interest expense decreased $3.0 million, or 9%, compared to the prior year due to a reduction in outstanding debt and lower interest rates on DP&L’s senior secured bonds.
During the year ended December 31, 2014, interest expense decreased $3.3 million, or 9%, compared to the prior year due to a reduction in outstanding debt and lower interest rates on DP&L’s senior secured bonds.
DP&L - Income Tax Expense
During the year ended December 31, 2015, Income tax expense decreased $4.6 million compared to the prior year primarily due to decreases in pre-tax income, an anticipated refund from the IRS for the filing of an amended 2011 predecessor tax return and an increase in the tax benefits of Internal Revenue Code Section 199 in 2015. Partially offsetting the decrease is a deferred tax adjustment related to the prior year expiration of the statute of limitations that did not occur in 2015.
During the year ended December 31, 2014, Income tax expense increased $21.1 million compared to the prior year primarily due to increases in pre-tax income, a 2014 deferred tax adjustment related to the expiration of the statute of limitations on the 2010 tax year and a decrease in the tax benefits of Internal Revenue Code Section 199 in 2014.
CAPITAL RESOURCES AND LIQUIDITY
Cash and cash equivalents for DPL and DP&L was $32.4 million and $5.4 million, respectively, at December 31, 2015. At that date, neither DPL nor DP&L had short-term investments. DPL and DP&L had aggregate principal amounts of debt outstanding of $2,013.7 million and $763.1 million, respectively.
Approximately $574.9 million of DPL'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.
Given our long-term debt obligations, we are subject to interest rate risk on debt balances that accrue interest at variable rates. When prudent, we will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations.
We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on our financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in the regulatory determinations could affect the cash flows and results of operations of our business.
CASH FLOWS
DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. The following tables provide summaries of the cash flows for DPL and DP&L:
The significant items that have impacted the cash flows for DPL and DP&L are discussed in greater detail below:
DPL - Net cash from operating activities
During the year ended December 31, 2015, Net cash from operating activities was primarily a result of Net loss adjusted for depreciation and amortization, the impairment of goodwill, deferred income taxes, and other non-cash adjustments, as well as collections of accounts receivable and collections of deferred regulatory costs.
During the year ended December 31, 2014, Net cash from operating activities was primarily a result of Net loss adjusted for depreciation and amortization, the impairment of goodwill and fixed-assets, deferred income taxes, a charge for the early redemption of debt, and other non-cash adjustments.
During the year ended December 31, 2013, Net cash from operating activities was primarily a result of Net loss adjusted for depreciation and amortization, the impairment of goodwill and fixed-assets and deferred income taxes.
DP&L - Net cash from operating activities
During the year ended December 31, 2015, the significant components of DP&L’s Net cash from operating activities were primarily the result of Net income adjusted for depreciation and amortization.
During the year ended December 31, 2014, the significant components of DP&L’s Net cash from operating activities were primarily the result of Net income adjusted for depreciation and amortization.
During the year ended December 31, 2013, the significant components of DP&L’s Net cash from operating activities were primarily a result of Net income adjusted for depreciation and amortization, as well as a non-cash charge related to the impairment of certain generation facilities.
DPL - Net cash from investing activities
During the year ended December 31, 2015, DPL’s cash from investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.
During the year ended December 31, 2014, DPL’s cash from investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.
During the year ended December 31, 2013, DPL’s cash from investing activities was primarily related to capital expenditures.
DP&L - Net cash from investing activities
During the year ended December 31, 2015, DP&L’s cash from investing activities was primarily related to capital expenditures, partially offset by insurance proceeds.
During the year ended December 31, 2014, DP&L’s cash from investing activities was primarily related to capital expenditures, partially offset by proceeds from the sale of property.
During the year ended December 31, 2013, DP&L’s cash from investing activities was primarily related to capital expenditures. In addition, DP&L received $14.2 million in insurance proceeds during the year, $6.6 million of which were from DPL’s MVIC subsidiary.
DPL - Net cash from financing activities
During the year ended December 31, 2015, DPL’s Net cash from financing activities primarily relates to the retirement of $474.5 million of debt, partially offset by a $325.0 million issuance of new debt.
During the year ended December 31, 2014, DPL’s Net cash used for financing activities primarily relates to the redemption of $335.0 million of debt and associated redemption premiums, partially offset by a $200.0 million issuance of new debt.
During the year ended December 31, 2013, DPL’s Net cash from financing activities primarily relates to the payment at maturity of $470.0 million of DP&L’s senior secured bonds, early redemption of $475.1 million of debt and debt issuance costs, partially offset by the issuance of $445.0 million of new senior secured bonds and the issuance of $200.0 million of new debt.
DP&L - Net cash from financing activities
During the year ended December 31, 2015, DP&L’s Net cash from financing activities primarily relates to the retirement of $314.5 million of long-term debt, partially offset by the issuance of $200.0 million of new debt.
During the year ended December 31, 2014, DP&L’s Net cash from financing activities primarily relates to $159.0 million in dividends.
During the year ended December 31, 2013, DP&L’s Net cash from financing activities primarily relates to $190.0 million in dividends and the issuance of $445.0 million of senior secured bonds, the proceeds of which were used to redeem DP&L’s senior secured bonds at maturity.
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 2016 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from debt financing as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under bank credit facilities will continue to be available to manage working capital requirements during those periods.
At the filing date of this annual report on Form 10-K, DPL and DP&L have access to the following revolving credit facilities:
DP&L has an unsecured revolving credit agreement with a syndicated bank group. Prior to refinancing the facility on July 31, 2015, as discussed below, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.
On July 31, 2015, DP&L refinanced its revolving credit facility, reducing the total size from $300.0 million to $175.0 million, with a $50.0 million letter of credit sublimit and a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million, and extending the term of the facility from May 2018 to July 2020. At December 31, 2015, DP&L had no draws under this facility and had two letters of credit in the aggregate amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this facility were not material during the years ended December 31, 2015 or 2014.
DPL has a revolving credit facility. This facility has a letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility. Prior to refinancing the facility on July 31, 2015, as discussed below, this facility was unsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million, and had a five year term expiring on May 10, 2018; with a springing maturity, meaning that if DPL had not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility would have been July 15, 2016.
On July 31, 2015, DPL refinanced its revolving credit facility, increasing the total size from $100.0 million to $205.0 million, with a $200.0 million letter of credit sublimit and a feature that provides DPL the ability to increase the size of the facility by an additional $95.0 million This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by DPLE secured by mortgages on assets of DPLE. The refinancing extended the life of the facility from May 2018 to July 2020. DPL's new credit facility has a springing maturity feature, replacing the previous springing maturity feature, providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019.
Capital Requirements
Construction Additions
Planned construction additions for 2016 relate primarily to new investments in and upgrades to DP&L’s electric generating station equipment and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors. As discussed previously, DP&L must separate its generation assets by January 1, 2017. Accordingly, estimated capital expenditures related to the generation assets of $104.0 million are not included in DP&L’s estimated spending for 2017 and 2018 in the table above. Those estimated costs are included in the DPL amounts.
DPL, primarily through its subsidiary DP&L, is projecting to spend an estimated $439.0 million in capital projects for the period 2016 through 2018. 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 $6.7 million within the next five years to reinforce its 138 kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.
Debt Covenants
The DPL revolving credit facility and term loan agreement have a Total Debt to EBITDA ratio that will be calculated, at the end of each fiscal quarter, by dividing total debt at the end of the current quarter by consolidated EBITDA for the four prior fiscal quarters. The ratio in the agreements is not to exceed 7.25 to 1.00 for any fiscal quarter ending September 30, 2015 through December 31, 2018; it then steps down to not exceed 6.25 to 1.00 for any fiscal quarter ending March 31, 2019 through December 31, 2019; and it then steps down not to exceed 5.75 to 1.00 for any fiscal quarter ending March 31, 2020 through July 31, 2020. As of December 31, 2015, this financial covenant was met with a ratio of 5.71 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, 2015, this financial covenant was met with a ratio of 3.04 to 1.00.
DP&L’s revolving credit facility and Bond Purchase and Covenants Agreement (financing document entered into in connection with the sale of the new $200 million of variable rate pollution control 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. First, prior to the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total Debt to Total Capitalization may not be greater than 0.65 to 1.00 at any time; and, on and after the date of completion of the separation of DP&L’s generation assets from its transmission and distribution assets, DP&L’s Total debt to Total Capitalization may not be greater than 0.75 to 1.00 at any time, except that required compliance with this financial covenant shall be suspended if DP&L maintains a rating of BBB- (or in the case of Moody’s Baa3) or higher with a stable outlook from at least one of Fitch Investors Service Inc., Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., as determined in accordance with the terms of the revolving credit facility. This covenant shall be suspended between January 1, 2017 and December 31, 2017, if during this same time, DP&L’s long-term indebtedness (as determined by the PUCO) is less than or equal to $750.0 million. The Total Debt to Capitalization
covenant is calculated at the end of each fiscal quarter as the sum of DP&L’s current and long-term portion of debt, divided by the total of DP&L’s shareholder’s equity and total debt. As of December 31, 2015, DP&L met this financial covenant with a Total Debt to Total Capitalization ratio of 0.39 to 1.00.
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, 2015, DP&L met this financial covenant with an EBITDA to Interest Expense ratio of 11.22 to 1.00.
Debt Ratings
During 2015, Fitch downgraded DPL's senior unsecured debt rating. Standard & Poor’s and Moody’s ratings did not change.
The following table outlines the debt ratings and outlook for DPL and DP&L, along with the effective dates of each rating.
Credit Ratings
The following table outlines the credit ratings (issuer/corporate rating) and outlook for each company, along with the effective dates of each rating and outlook for DPL and DP&L.
(a)
Rating relates to DPL’s Senior secured debt.
(b)
Rating relates to DPL's Senior unsecured debt.
(c)
Rating relates to DP&L’s Senior secured debt.
(d)
DPL ratings were updated in August 2015; DP&L ratings have not been updated since September 2014.
On August 7, 2015, Fitch downgraded DPL’s senior unsecured debt rating from BB Stable to BB- Stable, and assigned the rating of BB Stable to DPL's newly issued secured debt.
If the rating agencies were to reduce our debt or credit ratings further, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under certain contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities. Non-investment grade companies, such as DPL, may experience higher costs to issue new securities. DP&L is still considered investment grade by one of the three rating agencies above.
Off-Balance Sheet Arrangements
DPL - Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER, providing financial or performance assurance to third parties. These agreements are entered into
primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes. During the year ended December 31, 2015, 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, 2015, DPL had $17.3 million of guarantees to third parties for future financial or performance assurance under such agreements on behalf of DPLE. In addition, DPL had $1.9 million of guarantees on behalf of DPLER which were released in January 2016 as a result of the sale of DPLER. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE and present obligations of DPLER to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.5 million at December 31, 2015 and $1.6 million at December 31, 2014.
DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.5 million, of a $1,519.9 million debt obligation comprised of both fixed and variable rate securities with maturities between 2016 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015, 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, 2015, these include:
(a)
Total at DP&L operated units.
Long-term debt:
DPL’s Long-term debt at December 31, 2015 consists of DPL’s unsecured notes and secured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds and the Wright-Patterson Air Force Base (WPAFB) note. These long-term debt amounts include current maturities but exclude unamortized debt discounts, premiums and fair value adjustments.
DP&L’s Long-term debt at December 31, 2015 consists of its first mortgage bonds, tax-exempt pollution control bonds and the WPAFB note. These long-term debt amounts include current maturities but exclude unamortized debt discounts.
See Note 8 - Debt of the Notes to DPL’s Consolidated Financial Statements and Note 7 - Debt of the Notes to DP&L’s Financial Statements.
Interest payments:
Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2015.
Pension and postretirement payments:
At December 31, 2015, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 10 - Benefit Plans of Notes to DPL’s Consolidated Financial Statements and Note 9 - Benefit Plans of Notes to DP&L’s Financial Statements. These estimated future benefit payments are projected through 2025.
Coal contracts:
DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.
Purchase orders and other contractual obligations:
At December 31, 2015, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.
Reserve for uncertain tax positions:
Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $3.0 million at December 31, 2015, 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 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.
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; the valuation of goodwill; 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.
Impairments
In accordance with the provisions of GAAP relating to the accounting for goodwill, goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential
impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. See Note 7 - Goodwill and Other Intangible Assets of Notes to DPL’s Consolidated Financial Statements discussing the impairment of goodwill at DPL in 2015, 2014 and 2013.
In accordance with the provisions of GAAP relating to the accounting for impairments, long-lived assets to be held and used are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used are recognized based on the fair value of the asset. We determine the fair value of these assets based upon estimates of future cash flows, market value of similar assets, if available, or independent appraisals, if required. In analyzing the fair value and recoverability using future cash flows, we make projections based on a number of assumptions and estimates of growth rates, future economic conditions, assignment of discount rates and estimates of terminal values. An impairment loss is recognized if the carrying amount of the long-lived asset is not recoverable from its undiscounted cash flows. The measurement of impairment loss is the difference between the carrying amount and fair value of the asset. See Note 15 - Fixed-asset Impairment of Notes to DPL’s Consolidated Financial Statements and Note 13 - Fixed-asset Impairment of Notes to DP&L’s Financial Statements discussing the impairment of long-lived assets in 2014 and 2013.
Revenue Recognition (including Unbilled Revenue)
We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. The determination of the energy sales to customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. We recognize revenues using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, projected line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Given our estimation method and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.
Income Taxes
We are subject to federal and state income taxes. Our income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the U.S. Internal Revenue Service and other tax authorities. We regularly assess the potential outcome of tax examinations when determining the adequacy of our income tax provisions by considering the technical merits of the filing position, case law, and results of previous tax examinations. Accounting guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold and measurement requirements for financial statement reporting of our income tax positions. Tax reserves have been established, which we believe to be adequate in relation to the potential for additional assessments. Once established, reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While we believe that the amount of the tax reserves is reasonable, it is possible that the ultimate outcome of current or future examinations may be materially different than the reserve amounts.
Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.
Regulatory Assets and Liabilities
Application of the provisions of GAAP relating to regulatory accounting requires us to reflect the effect of rate regulation in DPL’s Consolidated Financial Statements and DP&L’s Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by non-regulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we
defer these costs as Regulatory assets that otherwise would be expensed by non-regulated companies. Likewise, we recognize Regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenses that are not yet incurred. Regulatory assets are amortized into expense and Regulatory liabilities are amortized into income over the recovery period authorized by the regulator.
We evaluate our Regulatory assets to determine whether or not they are probable of recovery through future rates and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period the assessment is made. We currently believe the recovery of our Regulatory assets is probable. See Note 3 - Regulatory Assets and Liabilities of Notes to DPL’s Consolidated Financial Statements and Note 3 - Regulatory Assets and Liabilities of Notes to DP&L’s Financial Statements.
AROs
In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time.
Pension and Postretirement Benefits
We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.
Effective January 1, 2016 we will apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and post-retirement plans. Refer to Note 1 - Overview and Summary of Significant Accounting Policies of Notes to DPL's Consolidated Financial Statements and Note 1 - Overview and Summary of Significant Accounting Policies of Notes to DP&L's Financial Statements. Also see Note 10 - Benefit Plans of Notes to DPL’s Consolidated Financial Statements and Note 9 - Benefit Plans of Notes to DP&L’s Financial Statements for more information.
Contingent and Other Obligations
During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We, however, believe such estimates and assumptions are reasonable.
LEGAL AND OTHER MATTERS
Discussions of legal and other matters are provided in Item 1 - Business "Environmental Matters", Item 1 - Business "Competition and Regulation" and Item 3 - Legal Proceedings. Such discussions are incorporated by reference in this Management's Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.
Recently Issued Accounting Pronouncements
A discussion of recently issued accounting pronouncements is 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 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.
Item 7A
Item 7A - Quantitative and Qualitative Disclosures about Market Risk
We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emission allowances, and changes in capacity prices and fluctuations in interest rates. We use various market risk-sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing. Our Commodity Risk Management Committee (CRMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures related to our DP&L operated generation units. The CRMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.
Commodity pricing risk
Commodity pricing risk exposure includes the impacts of weather, market demand, increased competition and other economic conditions. To manage the volatility relating to these exposures at our DP&L operated generation stations, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis and where applicable, we recognize a corresponding regulatory asset for above-market costs or a regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.
The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and wholesale sales requirements for 2016 under contract, sales requirements may change, particularly for retail load. 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 outages and electric generation station mix.
In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), signed into law in July 2010, contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. We are considered an end-user under the Dodd-Frank Act and therefore are exempt from most of the collateral and margining requirements. We are required to report our bilateral derivative contracts, unless our counterparty is a major swap participant or has elected to report on our behalf. Even though we qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us.
For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.
Commodity derivatives
To minimize the risk of fluctuations in the market price of commodities, such as coal, power, and 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, 2015, there are no coal derivatives.
The following table provides information regarding the volume and average market price of our power forward derivative contracts at December 31, 2015 and the effect to Net income if the market price were to increase or decrease by 10%:
Wholesale revenues
Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins (DP&L’s electric revenues in the wholesale market include sales to DPLER).
Approximately 46% of DPL’s and 45% of DP&L’s electric revenues for the year ended December 31, 2015 were from sales of excess energy and capacity in the wholesale market.
Approximately 46% of DPL’s and 45% of DP&L’s electric revenues for the year ended December 31, 2014 were from sales of excess energy and capacity in the wholesale market.
Approximately 45% of DPL’s and 45% of DP&L’s electric revenues for the year ended December 31, 2013 were from sales of excess energy and capacity in the wholesale market.
The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2015 of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale:
Capacity revenues and costs
As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year that runs from June 1 to May 31, has conducted auctions for capacity through the 2018/19 delivery year. The clearing prices for capacity during the PJM delivery periods from 2014/15 through 2018/19 are as follows:
Our computed average capacity prices by calendar year are reflected in the table below:
The above tables reflect the capacity prices after the transitional auctions discussed earlier. Substantially all of DP&L's capacity cleared in the CP auction. The results of these auctions could have a significant effect on DP&L's revenues in the future.
Future capacity auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and PJM’s business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s
capacity revenues and costs. Although DP&L had an approved RPM rider in place to recover or repay any excess capacity costs or revenues, the RPM rider only applies to customers supplied under our SSO. Beginning January 2016, the RPM rider will no longer exist since SSO load will be 100% sourced through the competitive bid.
The table below provides estimates of the effect on annual Net income (net of an estimated income tax of 35%) as of December 31, 2015 of a hypothetical increase or decrease of $10/MW-day in the capacity auction price. The table shows the impact resulting from capacity revenue changes.
Capacity revenues and costs are also impacted by, among other factors, the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. In determining the capacity price sensitivity above, we did not consider the impact that may arise from the variability of these other factors.
The capacity clearing prices listed above reflect the FERC’s newly approved proposal made by PJM to implement a new CP program. The FERC’s conditions on approval include requiring PJM to make additional filings to change certain energy market rules to coordinate better with the CP program and to make annual filings on the CP performance hours used in its calculations. The FERC’s order approved transitional mechanisms under which the results of the auctions under the RPM program for the 2016/17 and 2017/18 periods would be modified based on transitional CP auctions that were held in the third quarter of 2015. The first full CP auction was also held in the third quarter of 2015 for the 2018/19 period.
As approved, the CP program offers the potential for higher capacity revenues, combined with substantially increased penalties for non-performance or under-performance during certain periods identified as “capacity performance hours”. This linkage between non- or under-performance during certain specific hours means that a generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150% of the net Cost of New Entry, which is a value computed by PJM. This level is likely to be larger than the capacity price established under the CP program, so that the potential exists that participation in the CP program could result in capacity penalties that exceed capacity revenues.
At present, DP&L is unable to project whether the CP program will be beneficial or negative to DP&L’s operations, but the results could be material to DP&L’s operations.
Fuel and purchased power costs
DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the years ended December 31, 2015, 2014 and 2013 were 59%, 42% and 45%, respectively. We have a significant portion of projected 2016 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2 allowances for 2016; 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 2016 depending on NOX emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and electric generation station mix.
Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity. We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal generation costs.
The table below provides the effect on annual Net income (net of an estimated income tax at 35%) as of December 31, 2015, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power:
Interest rate risk
As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates, which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL and DP&L have both fixed-rate and variable rate long-term debt. DPL’s variable-rate debt consists of a $125 million secured term loan with a syndicated bank group. DP&L’s variable-rate debt is comprised of $200 million of bank held pollution control bonds. Both variable-rate bonds bear interest based on an underlying interest rate index, typically LIBOR. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 8 - Debt of Notes to DPL’s Consolidated Financial Statements and Note 7 - Debt of Notes to DP&L’s Financial Statements.
The carrying value of DPL’s debt was $2,009.4 million at December 31, 2015, consisting of DPL’s unsecured notes, secured term loan, Capital Trust II securities along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds and the WPAFB note. All of DPL’s existing debt was adjusted to fair value at the Merger date according to FASC 805. The fair value of this debt at December 31, 2015 was $1,975.3 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:
Principal payments and interest rate detail by contractual maturity date
The carrying value of DP&L’s debt was $762.9 million at December 31, 2015, consisting of its first mortgage bonds, tax-exempt pollution control bonds and the WPAFB note. The fair value of this debt at December 31, 2015 was $764.2 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.
Principal payments and interest rate detail by contractual maturity date
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, 2015 and 2014 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, 2015 and 2014, we did not hold any market risk sensitive instruments which were entered into for trading purposes.
Carrying value and fair value of debt with one percent interest rate risk
(a)
Carrying value includes unamortized debt discounts and premiums.
(a)
Carrying value includes unamortized debt discounts and premiums.
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 $1,650.3 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 $325.0 million variable-rate long-term debt outstanding at December 31, 2015.
DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $564.2 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 $200.0 million variable-rate long-term debt outstanding at December 31, 2015.
Equity price risk
At December 31, 2015, approximately 17% of the defined benefit pension plan assets were comprised of investments in equity securities and 83% 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
$60.3 million at December 31, 2015. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6.0 million reduction in fair value at December 31, 2015 and approximately a $0.2 million increase to the 2016 pension expense.
Credit risk
Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We limit our credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been originated. We use the three leading corporate credit rating agencies and other current market-based qualitative and quantitative data to assess the financial strength of counterparties on an ongoing basis. We may require various forms of credit assurance from counterparties in order to mitigate credit risk.
Item 8
Item 8 - Financial Statements and Supplementary Data
This report includes the combined filing of DPL and DP&L. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.
FINANCIAL STATEMENTS
DPL INC.
Report of Independent Registered Public Accounting Firm
To the Board of Directors of DPL Inc.
We have audited the accompanying consolidated balance sheets of DPL Inc. as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income/(loss), cash flows, and shareholder’s equity for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule “Schedule II - Valuation and Qualifying Accounts” for each of the three years in the period ended December 31, 2015. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of DPL Inc. at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
February 23, 2016
Indianapolis, Indiana
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
(a)
Goodwill impairment of $135.8 million in 2014 has been reclassified to Discontinued operations in the Consolidated Statement of Operations.
See Notes to Consolidated Financial Statements.
(a)
1,500 shares authorized
(b)
$5.9 million of dividends declared in 2012 were reversed in 2013.
See Notes to Consolidated Financial Statements.
DPL Inc.
Notes to Consolidated Financial Statements
For the years ended December 31, 2015, 2014 and 2013
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’s one reportable segment is the Utility segment, comprised of its DP&L subsidiary. See Note 14 - Business Segments for more information relating to reportable segments. The terms “we”, “us”, “our” and “ours” are used to refer to DPL and its subsidiaries.
On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly-owned subsidiary of AES. Following the merger of DPL and Dolphin Subsidiary II, Inc., DPL became an indirectly wholly-owned subsidiary of AES.
DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission services are still regulated. DP&L has the exclusive right to provide such service to its approximately 517,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer supplied 100% of the generation for SSO customers and starting January 2016, SSO is now 100% competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.
In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014 the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L is required to sell or transfer its generation assets by January 1, 2017 and continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale.
DPLER was sold by DPL on January 1, 2016. DPLER sold competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER had approximately 125,000 customers located throughout Ohio. DPLER’s operations included those of its wholly-owned subsidiary MC Squared through April 1, 2015, when DPLER sold MC Squared. Approximately 110,000 of DPLER’s customers were also electric distribution customers of DP&L. DPLER did not own any transmission or generation assets, and it purchased all of its electric energy from DP&L to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the area. See Note 16 - Discontinued Operations for more information.
DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity, and MVIC, our captive insurance company that provides insurance services to us and our other subsidiaries. Effective February 1, 2016, DPLE was renamed AES Ohio Generation, LLC. DPL owns all of the common stock of its subsidiaries.
DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.
DPL and its subsidiaries employed 1,219 people at January 31, 2016, of which 1,189 were employed by DP&L. Approximately 60% of all DPL employees are under a collective bargaining agreement which expires on October 31, 2017.
Financial Statement Presentation
We prepare Consolidated Financial Statements for DPL. DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP. DP&L’s undivided ownership interests in certain coal-fired generating stations are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger date. Operating revenues and expenses are included on a pro rata basis in the corresponding lines in the Consolidated Statement of Operations. See Note 4 - Property, Plant and Equipment for more information.
All material intercompany accounts and transactions are eliminated in consolidation.
Certain immaterial 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; assets and liabilities related to employee benefits; goodwill; and intangibles.
Valuation of Goodwill
FASC 350, “Intangibles - Goodwill and Other”, requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. See Note 7 - Goodwill and Other Intangible Assets for information regarding the impairments of goodwill in 2015, 2014 and 2013.
Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.
All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Consolidated Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.
Allowance for Uncollectible Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.
Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.0 million, $1.5 million and $1.5 million in the years ended December 31, 2015, 2014 and 2013, respectively.
For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.
For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.
Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable. See Note 15 - Fixed-asset Impairment for more information.
Repairs and Maintenance
Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates that approximated 4.6% in 2015, 5.3% in 2014 and 5.8% in 2013. Depreciation expense was $125.9 million, $128.1 million and $120.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Regulatory Accounting
As a regulated utility, we apply 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 Assets and Liabilities for more information.
Inventories
Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.
Intangibles
Intangibles include 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. See Note 7 - Goodwill and Other Intangible Assets for additional information.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statement of Operations.
Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 - Regulatory Assets and Liabilities 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 9 - Income Taxes for additional information.
Financial Instruments
We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2015, 2014 and 2013, were $49.9 million, $50.8 million and $50.5 million, respectively.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Restricted Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the sale of DPLER on January 1, 2016. See Note 16 - Discontinued Operations for additional information regarding the sale of DPLER.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 - Derivative Instruments and Hedging Activities for additional information.
Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. Insurance and Claims Costs on DPL’s Consolidated Balance Sheets associated with MVIC include estimated liabilities of approximately $5.9 million and $6.4 million at December 31, 2015 and 2014, respectively. In addition, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers of approximately $13.7 million and $15.6 million at December 31, 2015 and 2014, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.
Pension and Postretirement Benefits
We recognize, in our Consolidated Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.
Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of ASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.
The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015, nor will it impact future remeasurements. This change in approach will impact the service cost and interest cost recorded in 2016 and future years. It will also impact the actuarial gains and losses recorded in future years, as well as the amortization thereof.
The expected 2016 service costs and interest costs included in Note 10 - Benefit Plans reflect the change in methodology described above. The impact of the change in approach on expected service costs in 2016 is shown below:
See Note 10 - Benefit Plans for more information.
Related Party Transactions
In the normal course of business, DPL enters into transactions with related parties. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements.
See Note 13 - Related Party Transactions for more information on Related Party Transactions.
DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 2015 and 2014, 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, 2015 and December 31, 2014, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 - Debt for additional information.
In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.
New accounting pronouncements adopted
ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes
Effective December 31, 2015, we prospectively adopted ASU No. 2015-17, which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As we elected to apply this ASU prospectively, prior periods were not adjusted.
ASU No. 2015-13, Derivatives and Hedging (Topic 815):Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Market
In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815, Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As we had designated qualifying contracts as normal purchase or normal sales, there was no impact on our financial statements upon adoption of this standard.
Accounting pronouncements issued but not yet effective
ASU No. 2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. We are currently evaluating the applicability and materiality of the standard, but we do not anticipate a material impact on our consolidated financial statements.
ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. We will adopt this standard on January 1, 2016, which is not expected to have a material impact on our consolidated financial statements.
ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30)
In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, DPL had approximately $16.1 million in deferred financing costs classified in other current and other non-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.
ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements
In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, we had deferred financing costs related to lines of credit of approximately $3.1 million recorded within Other noncurrent assets that would not be reclassified upon adoption of this standard.
ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory
In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As we already used the net realizable value to make lower of cost or market determinations, there will be no impact on our financial statements upon adoption of this standard.
ASU No. 2015-05, Intangibles - Goodwill and Other: Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. As all of our cloud computing arrangements will continue to be accounted for as service agreements, there will be no impact on our financial statements upon the adoption of this standard.
ASU No. 2014-05, Presentation of Financial Statements: Going Concern
The FASB recently issued ASU 2014-15 “Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016. ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.
ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contract with Customers (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. We have not yet selected a transition method and are currently evaluating the impact of adopting the standard on our financial statements.
ASU No. 2015-02, Consolidation - Amendments to the Consolidation Analysis (Topic 810)
In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the Variable Interest Entity (VIE) guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We do not expect this standard to have an impact on our financial statements upon adoption.
Note 2 - Supplemental Financial Information
Accounts receivable of $31.0 million and $64.4 million as of December 31, 2015 and 2014 have been excluded from the above table as they have been reclassified as "Assets held for sale". See Note 16 - Discontinued Operations.
Accumulated Other Comprehensive Income / (Loss)
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2015, 2014 and 2013 are as follows:
The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2015 and 2014 are as follows:
Note 3 - Regulatory Assets and Liabilities
In accordance with FASC 980, we have recognized total regulatory assets of $194.3 million and $211.7 million at December 31, 2015 and 2014, respectively, and total regulatory liabilities of $151.4 million and $128.5 million at December 31, 2015 and 2014, respectively. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 1 - Overview and Summary of Significant Accounting Policies for accounting policies regarding Regulatory Assets and Liabilities.
The following table presents DPL’s Regulatory assets and liabilities:
A - Recovery of incurred costs without a rate of return.
B - Recovery of incurred costs plus rate of return.
C - Balance has an offsetting liability resulting in no effect on rate base.
D - Recovery not yet determined, but is probable of occurring in future rate proceedings.
Regulatory assets
Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. As part of the PUCO approval process, an outside auditor reviews fuel costs and the fuel procurement process. The audit for 2014 is in process. The costs recovered through the fuel rider have decreased significantly over the past three years as more SSO supply is provided through the competitive bid. While no further fuel or purchased power costs will be recoverable through the rider, it will continue for up to six months to allow for recovery of the ending deferral amount.
Fuel costs - long-term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs.
Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. All such costs have now been recovered.
Energy efficiency program costs represent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2014 and 2015, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million per year, after income taxes.
Pension 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.
Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of tax benefits previously provided to customers. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.
Unrecovered OVEC charges represent the portion of capacity charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. DP&L expects to recover these costs through a future rate proceeding.
Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.
Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities' Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan
to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.
Generation separation costs represent financing, redemption and other costs related to the divestiture of DP&L’s generation assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&L requested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Consumer education campaign represents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.
Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Regulatory liabilities
Energy efficiency program costs see “Regulatory Assets - Energy efficiency program costs” above.
Competitive bidding represents costs associated with the development and implementation of a Competitive Bidding Process, establishing contracts to supply power for a portion of DP&L’s Standard Service Offer load, as well as the net over/under recovery of the cost of the power purchased from the bid winners.
Transmission costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.
Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers.
Estimated costs of removal - regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.
Postretirement benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.
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, 2015 and 2014:
DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2015, DP&L had $39.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the Statements of Operations, and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.
Coal-fired facilities
DP&L’s undivided ownership interest in such facilities at December 31, 2015, is as follows:
Each of the above generating units has SCR and FGD equipment installed.
Beckjord Unit 6 was retired effective October 1, 2014, and DP&L’s sale of its interest in East Bend closed on December 30, 2014.
AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.
Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.
Changes in the Liability for Generation AROs
Asset Removal Costs
We continue to record costs of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $121.8 million and $119.3 million in estimated costs of removal at December 31, 2015 and 2014, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 - Regulatory Assets and Liabilities for additional information.
Changes in the Liability for Transmission and Distribution Asset Removal Costs
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, 2015 and 2014. See Note 6 - Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
Fair value hierarchy
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
•
Level 1 (quoted prices in active markets for identical assets or liabilities);
•
Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); and
•
Level 3 (unobservable inputs).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.
We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2015 and 2014.
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 2016 to 2061.
Master trust assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.
DPL had $0.7 million ($0.5 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015, and $0.8 million ($0.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.
Various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, an immaterial amount of unrealized gains were reversed into earnings. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.
The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DPL was determined as follows:
(a)
Includes credit valuation adjustment.
The fair value of assets and liabilities at December 31, 2014 and the respective category within the fair value hierarchy for DPL was determined as follows:
(a)
Includes credit valuation adjustment.
Our financial instruments are valued using the market approach in the following categories:
•
Level 1 inputs are used for derivative contracts, such as heating oil futures, and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.
•
Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit.
•
Level 3 inputs, such as financial transmission rights, are considered a Level 3 input because the monthly auctions are considered inactive. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.
Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered
Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.
Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.
Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $39.0 million ($25.4 million after tax) and $2.5 million ($1.6 million after tax) during the 12 months ended December 31, 2015 and 2014, respectively. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ($26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 - Property, Plant and Equipment for more information about AROs.
When evaluating impairment of goodwill and long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
(a)
See Note 15 - Fixed-asset Impairment for further information
(b)
See Note 7 - Goodwill and Other Intangible Assets for further information
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, 2015, DPL had the following outstanding derivative instruments:
At December 31, 2014, DPL had the following outstanding derivative instruments:
Cash flow hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.
We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.
We also entered into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. These interest rate derivative contracts were settled in the third quarter of 2013. We do not hedge all interest rate exposure. We reclassify gains and losses on interest rate derivative hedges out of AOCI and into earnings in those periods in which hedged interest payments occur.
The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:
(a)
The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.
Derivatives not designated as hedges
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures and certain forward power contracts.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of results of operations on an accrual basis.
Regulatory assets and liabilities
In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.
The following tables show the amount and classification within the consolidated statements of results of operations or balance sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the years ended December 31, 2015, 2014 and 2013:
The following tables show the fair value, balance sheet classification and hedging designation of DPL’s derivative instruments at December 31, 2015 and 2014.
(a)
Includes credit valuation adjustment.
(a)
Includes credit valuation adjustment.
As of December 31, 2014, the above table includes Forward power contracts in a short-term asset position of $11.1 million. This table does not include a short-term asset position of $0.1 million of Forward power contracts that had been, but no longer need to be, accounted for as derivatives at fair value that are to be amortized to earnings over the remaining term of the associated forward contract.
Credit risk-related contingent features
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss.
The aggregate fair value of DPL’s derivative instruments that are in a MTM loss position at December 31, 2015 is $27.5 million. This amount is offset by $8.0 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $17.9 million. Since our debt is below investment grade, we could have to post collateral for the remaining $1.6 million.
Note 7 - Goodwill and Other Intangible Assets
Goodwill
The following table summarizes the changes in Goodwill by reportable segment for the years ended December 31, 2015, 2014 and 2013:
In connection with the acquisition of DPL by AES, DPL allocated the purchase price to goodwill for two reporting units, the DP&L reporting unit, which included DP&L and other entities, and DPLER. Of the total goodwill, approximately $2.4 billion was allocated to the DP&L reporting unit and the remainder was allocated to DPLER. Goodwill represented the value assigned at the Merger date, as adjusted for subsequent changes in the purchase price allocation, less recognized impairments.
DPLER Reporting Unit
During the first quarter of 2014, we performed an interim impairment test on the $135.8 million in goodwill at our DPLER reporting unit. During the second quarter of 2014, we finalized the work to determine the implied fair value for the DPLER reporting unit. There were no further adjustments to the full impairment of $135.8 million recognized in the first quarter. DPLER was sold on January 1, 2016 and is presented in discontinued operations on the Consolidated Statement of Operations. See Note 16 - Discontinued Operations for additional information.
DP&L Reporting Unit
During the fourth quarter of 2015, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $317.0 million. The reporting unit failed Step 1 as its fair value was less than its carrying amount, which was primarily due to a decrease forecasted in dark spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from the CP product. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were forward commodity price curves, expected revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to have no implied fair value after the hypothetical purchase price allocation under the accounting guidance for business combinations; therefore, a full impairment of the remaining goodwill balance of $317.0 million was recognized. The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no financial statement tax benefit related to the impairment.
During the fourth quarter of 2013, DPL performed its annual goodwill impairment test and recognized a goodwill impairment at its DP&L reporting unit of $306.3 million. In performing the annual goodwill impairment test as of October 1, 2013, Step 1 of the test failed as the fair value of the reporting unit no longer exceeded its carrying amount due primarily to lower estimates of capacity prices in future years as well as lower dark spreads contributing
to lower overall operating margins for the business. The fair value of the reporting unit was determined under the income approach using a discounted cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model were capacity price curves, amount of the non-bypassable charge, commodity price curves, dispatching, valuation of regulatory assets and liabilities, discount rates and deferred income taxes. In Step 2, goodwill was determined to have an implied fair value of $317.0 million after the hypothetical purchase price allocation under the accounting guidance for business combinations.
The goodwill associated with the Merger is not deductible for tax purposes. Accordingly, there is no cash or financial statement tax benefit related to the impairment.
Note 8 - Debt
(a)
Range of interest rates for the years ended December 31, 2015 and 2014, respectively.
(b)
Note payable to related party. See Note 13 - Related Party Transactions for additional information.
At December 31, 2015, maturities of long-term debt are summarized as follows:
Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method.
Significant transactions
On July 1, 2015, the $35.3 million of DP&L's 4.7% pollution control bonds due January 2028 and $41.3 million of DP&L's 4.8% pollution control bonds due January of 2034 were called at par and were redeemed with cash.
On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, with a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and maturity date of July 2020. At December 31, 2015, there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 2015 or 2014. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.
On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bonds due November 2040, terminated the amended standby letter of credit facilities that supported these pollution control bonds, and called $137.8 million of 4.8% pollution control bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with new variable interest rate pollution control bonds secured by first mortgage bonds in an equivalent amount. In connection with the sale of the new pollution control bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L.
On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. Substantially all property, plant and equipment of DP&L is subject to the lien of the First and Refunding Mortgage. Substantially concurrent with this transaction, DP&L redeemed $470.0 million of previously outstanding first mortgage bonds.
On July 31, 2015, DPL refinanced its revolving credit facility. The new facility has a total size of $205.0 million, a $200.0 million letter of credit sublimit, a feature that provides DPL the ability, under certain circumstances, to increase the size of the facility by an additional $95.0 million and a maturity date of July 2020. DPL's new credit facility also has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by DPLE secured by mortgages on assets of DPLE. At December 31, 2015, there were two letters of credit in the amount of $3.0 million outstanding under this facility, with the remaining
$202.0 million of the revolving credit facility remaining available to DPL. Fees associated with this facility were not material during the years ended December 31, 2015 or 2014.
Prior to refinancing the facility on July 31, 2015, this facility was unsecured and had a borrowing limit of $100.0 million with a $100.0 million letter of credit sublimit, was able to be increased in size by DPL by an additional $50.0 million and had a five-year term expiring on May 10, 2018; with a springing maturity, meaning that if DPL had not refinanced its senior unsecured bonds due October 2016 before July 15, 2016, then the maturity of this facility would have been July 15, 2016.
Also on July 31, 2015, DPL refinanced its term loan, paying down the outstanding amount of $160.0 million using proceeds from the new term loan of $125.0 million and a combination of cash on hand and draws on short term credit facilities. The new term loan extends the term to July of 2020, pushing back required principal payments to 2017, and providing a mechanism for DPL to request additional term loans to refinance existing indebtedness. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019. This facility is secured by a pledge of common stock that DPL owns in DP&L, limited to the amount permitted to be pledged under certain Indentures dated October 3, 2011 and October 6, 2014 between DPL and Wells Fargo Bank, NA and U.S. Bank National Association, respectively, as Trustee and a limited recourse guarantee by DPLE secured by mortgages on assets of DPLE. The new term loan has a springing maturity feature providing that if, before July 1, 2019, DPL has not refinanced its senior unsecured bonds due October 2019 to have a maturity date that is at least six months later than July 31, 2020, then the maturity of this facility shall be July 1, 2019.
In October 2014, DPL repaid $5.0 million of the note due to Capital Trust II, which used the funds to repurchase securities in the open market at a slight premium. Subsequent to repurchasing these securities, Capital Trust II immediately retired them.
In connection with the closing of the Merger, DPL assumed $1,250.0 million of debt that Dolphin Subsidiary II, Inc., a subsidiary of AES, issued on October 3, 2011 to partially finance the Merger. The $1,250.0 million was issued in two tranches. The first tranche was $450.0 million of five year senior unsecured notes issued with a 6.50% coupon maturing on October 15, 2016. The second tranche was $800.0 million of ten year senior unsecured notes issued with a 7.25% coupon maturing on October 15, 2021. In December 2013, DPL executed an Open Market Repurchase Program and successfully bought back $20.0 million of both the first and second tranche of senior unsecured notes and immediately retired them.
In October 2014, DPL closed a $200.0 million issuance of senior unsecured bonds. These new bonds were priced at 6.75% and mature on October 1, 2019. Proceeds from the issuance, in addition to a draw on the DPL revolving line of credit and cash on hand, were used to settle a tender offer for $300.0 million of the 6.50% senior unsecured notes maturing October 15, 2016. After this transaction, the DPL Inc. 6.5% Senior Notes due 2016 had an outstanding principle balance of $130.0 million
On January 6, 2016, DPL issued a Notice of Partial Redemption to the Trustee (Wells Fargo Bank N.A.) on the DPL Inc. 6.5% Senior Notes due 2016 (a component of the Dolphin Subsidiary II, Inc. debt). DPL notified the trustee that it was calling $73.0 million of the $130.0 million outstanding principal amount of these notes. The record date of this redemption was January 21, 2016, and the redemption date was February 5, 2016. These bonds were redeemed at par plus accrued interest and a make-whole premium of $2.4 million.
Debt covenants and restrictions
DP&L’s unsecured revolving credit agreement and Bond Purchase and Covenants Agreement (financing document entered into in connection with the sale of the new $200.0 million of variable rate pollution control bonds, 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 EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.
DPL’s revolving credit agreement and term loan have two financial covenants. The first financial covenant, a Total Debt to EBITDA ratio, is calculated at the end of each fiscal quarter by dividing total debt at the end of the current
quarter by consolidated EBITDA for the four prior fiscal quarters. The second financial covenant is an EBITDA to Interest Expense ratio that is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.
As of December 31, 2015, DP&L and DPL were in compliance with all debt covenants, including the financial covenants described above.
DP&L does not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL. DPL’s secured revolving credit agreement, secured term loan, and senior unsecured notes due 2019 restrict dividend payments from DPL to AES, such that DPL cannot make dividend payments unless at the time of, and/or as a result of, the distribution, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions. As of December 31, 2015, DPL’s leverage ratio was at 1.03 to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015, 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).
Note 9 - Income Taxes
DPL’s components of income tax expense on continuing operations were as follows:
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, 2015, 2014 and 2013:
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.
(a)
The statutory tax rate of 35% was applied to pre-tax earnings.
(b)
Includes expense of $0.2 million, $0.4 million and $0.0 million in the years ended December 31, 2015, 2014, and 2013, respectively, of income tax related to adjustments from prior years.
(c)
The Other non-current liabilities caption includes deferred tax assets of $26.0 million in 2015 and $27.1 million in 2014 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $17.2 million in 2015 and $18.9 million in 2014. These net operating loss carryforwards expire from 2016 to 2030.
(d)
Amounts are included within Other prepayments and current assets and Other current liabilities on the Consolidated Balance Sheet of DPL at December 31, 2014.
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.
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:
Of the December 31, 2015 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.
We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued as well as the expense / (benefit) recorded were not material for the years ended December 31, 2015, 2014 and 2013.
Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal - 2010 and forward
State and Local - 2010 and forward
None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations.
The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010. The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013. As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense in 2013.
Note 10 - Benefit Plans
Defined contribution plans
DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.
Certain non-union employees become eligible to participate in the management plan on the first day of the month following the first full calendar month of employment; provided the employee worked at least 160 hours in that calendar month. Union employees become eligible to participate in the union plan on the first day of the first month following 30 days of employment. Effective January 1, 2016, employees in both plans are eligible to participate upon date of hire.
Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,100 for 2015 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions.
For the years ended December 31, 2015, 2014 and 2013, DP&L's contributions to all defined contribution plans were $4.8 million, $4.7 million and $4.8 million per year, respectively.
Defined benefit plans
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.
Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.
In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. We also include our net liability to our partners related to our share of their pension costs within Pension, retiree and other benefits on our Consolidated Balance Sheets.
We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.
Postretirement benefits
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.
The following tables set forth the changes in our pension and postemployment benefit plans’ obligations and assets recorded on the balance sheets at December 31, 2015 and 2014. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presented for postemployment obligations include both health and life insurance benefits.
The accumulated benefit obligation for our defined benefit pension plans was $401.2 million and $431.0 million at December 31, 2015 and 2014, respectively.
The net periodic benefit cost of the pension and postretirement plans were:
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2016 are:
Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
At December 31, 2015, we are maintaining our long term rate of return assumption of 6.50% for pension plan assets. In addition, we are decreasing our long-term rate of return assumption to 3.90% from 4.50% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our long-term portfolio mixes. Also, at December 31, 2015, we have increased our assumed discount rate to 4.49% from 4.02% for pension and to 4.10% from 3.71% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in pension expense of approximately $3.5 million. A one percent decrease in the rate of return assumption for pension would result in an increase in pension expense of approximately $3.5 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.2 million to 2016 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3 million to 2016 pension expense. A one percent change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.
In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2015. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.
Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 1 - Overview and Summary of Significant Accounting Policies for more information.
In future periods, differences in the actual return on pension and other post-employment benefit plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions, if any to the plans.
The weighted average assumptions used to determine benefit obligations at December 31, 2015, 2014 and 2013 were:
The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013 were:
The assumed health care cost trend rates at December 31, 2015, 2014 and 2013 are as follows:
The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postemployment benefit cost and the accumulated postemployment benefit obligation:
Pension plan assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.
Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the Plan’s long-term objectives. The long-term target allocations for plan assets are 18% - 38% for equity securities and 58% - 86% 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 allocation to a core property fund, as well as a small allocation to a hedge 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 and the Common collective fund are measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.
The following table summarizes our target pension plan allocation for 2015:
The fair values of our pension plan assets at December 31, 2015 by asset category are as follows:
(a)
This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
The fair values of our pension plan assets at December 31, 2014 by asset category are as follows:
(a)
This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value.
(d)
This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
The fair values of our other postemployment benefit plan assets at December 31, 2015 by asset category are as follows:
(a)
This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.
The fair values of our other postemployment benefit plan assets at December 31, 2014 by asset category are as follows:
(a)
This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.
Pension funding
We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $5.0 million, $0.0 million, and $0.0 million to the pension plan during the years ended December 31, 2015, 2014 and 2013, respectively.
We expect to make contributions of $0.4 million to our SERP in 2016 to cover benefit payments. We also expect to contribute $1.1 million to our other postemployment benefit plans in 2016 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January 2016.
The Pension Protection Act of 2006 (the Act) contained new requirements for our single employer defined benefit pension plan. In addition to establishing a 100% funding target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2015 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 112.54% and is estimated to be 112.54% until the 2016 status is certified in September 2016 for the 2016 plan year. The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, grants plan sponsors certain relief from funding requirements and benefit restrictions of the Act.
Benefit payments, which reflect future service, are expected to be paid as follows:
Note 11 - Equity
Redeemable Preferred Stock of Subsidiary
DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015 and 2014. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding at December 31, 2015 or 2014. The table below details the preferred shares outstanding at December 31, 2015:
(a)
Carrying value is fair value at the Merger date plus cumulative accrued dividends, of which there were none at December 31, 2015 and 2014.
The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends, of which there were none at December 31, 2015. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Consolidated Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.
Dividend Restrictions
DPL’s Amended Articles of Incorporation (the Articles) contain provisions which state that DPL may not make a distribution to its shareholder or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no Event of Default (as defined in the Articles) and no such Event of Default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, DPL’s leverage ratio does not exceed 0.67 to 1.00 and DPL’s interest coverage ratio is not less than 2.50 to 1.00 or, (b)(ii) if such ratios are not within the parameters, DPL’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. Further, the restrictions on the payment of distributions to a shareholder and the making of loans to its affiliates (other than subsidiaries) cease to be in effect if the three major credit rating agencies confirm that a lowering of DPL’s senior long-term debt rating below investment grade by the credit rating agencies would not occur without these restrictions.
As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not affected DP&L’s ability to pay cash dividends and, at December 31, 2015, DP&L’s retained earnings of $437.3 million were all available for common stock dividends payable to DPL. We do not expect this restriction to have an effect on the payment of cash dividends in the future. DPL records dividends on preferred stock of DP&L within Interest expense on the Statements of Operations.
Common Stock
Effective on the Merger date, DPL adopted Amended Articles of Incorporation providing for 1,500 authorized common shares, of which one share is outstanding at December 31, 2015.
As described above, DPL’s Amended Articles of Incorporation contain restrictions on DPL’s ability to make dividends, distributions and affiliate loans (other than to its subsidiaries), including restrictions of making such dividends, distributions and loans if certain financial ratios exceed specified levels and DPL’s senior long-term debt rating from a rating agency is below investment grade. As of December 31, 2015, DPL’s leverage ratio was at 1.03
to 1.00 and DPL’s senior long-term debt rating from all three major credit rating agencies was below investment grade. As a result, as of December 31, 2015, DPL was prohibited under its Articles of Incorporation from making a distribution to its shareholder or making a loan to any of its affiliates (other than its subsidiaries).
DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2015. 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.
Note 12 - Contractual Obligations, Commercial Commitments and Contingencies
DPL - Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.
At December 31, 2015, DPL had $17.3 million of guarantees on behalf of DPLE to third parties for future financial or performance assurance under such agreements. In addition, DPL had $1.9 million of guarantees on behalf of DPLER which were released in January 2016 as a result of the sale of DPLER. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE and present obligations of DPLER to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. All guarantees on behalf of DPLER were terminated in January 2016. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $0.5 million and $1.6 million at December 31, 2015 and 2014, respectively.
To date, DPL has not incurred any losses related to these guarantees and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees.
Equity Ownership Interest
DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.5 million, of a $1,519.9 million debt obligation comprised of both fixed and variable rate securities with maturities between 2016 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015, we have no knowledge of such a default.
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2015, these include:
(a)
Total at DP&L operated units.
Coal contracts:
DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2015, 73% of our future committed coal obligations are with a single supplier. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.
Purchase orders and other contractual obligations:
At December 31, 2015, DPL had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates.
Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2015, cannot be reasonably determined.
Environmental Matters
DPL’s and DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include:
•
The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions,
•
Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,
•
Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO2, particulates, mercury, acid gases, NOX, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,
•
Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs,
•
Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
•
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have accruals for loss contingencies of approximately $0.9 million for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.
We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.
Note 13 - Related Party Transactions
Service Company
In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in
fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.
The following table provides a summary of these transactions:
DPL Capital Trust II
DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective in 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $0.3 million and $0.3 million at December 31, 2015 and 2014, 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, 2015 and 2014, respectively, that was established upon the Trust’s deconsolidation in 2003. See Note 8 - Debt for additional information.
In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.
Income taxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries. Under a tax sharing agreement with AES, DPL is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DPL had a net payable balance under this agreement of $50.5 million and $16.1 million as of December 31, 2015 and 2014, respectively, which is recorded in Accrued taxes on the accompanying Consolidated Balance Sheets.
Note 14 - Business Segments
DPL had two reportable segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment) and DPLER (Competitive Retail segment which included DPLER's wholly-owned subsidiary, MC Squared). This is how we viewed our business and made decisions on how to allocate resources and evaluate performance.
The Competitive Retail segment, DPLER’s competitive retail electric service business, was sold on January 1, 2016 (see Note 16 - Discontinued Operations). DPL now operates through one segment, the Utility segment. Segment disclosures for 2014 and 2013 have not been restated to show the competitive retail segment as a discontinued operation and therefore do not tie to the Statements of Operations.
The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and deliver electricity to residential, commercial, industrial and governmental customers. DP&L generates electricity at five coal-fired electric generating stations and distributes electricity to approximately 517,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sold electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law.
The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. Intercompany sales from DP&L to DPLER were based on fixed-price contracts for each customer; the price approximated market prices for wholesale power at the inception of each customer’s contract. These agreements were terminated in connection with the sale of DPLER on January 1, 2016.
Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs, which include interest expense on DPL’s debt. Management evaluates segment performance based on gross margin. 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:
(a)
For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
(b)
Includes assets held for sale related to the sale of DPLER.
(a)
For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
(a)
For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.
Note 15 - Fixed-asset Impairment
East Bend (DP&L) - During the first quarter of 2014, DPL tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Kentucky jointly-owned by DP&L. Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2.7 million using the market approach. As a result, we recognized an asset impairment expense of $11.5 million. East Bend is reported in the Utility segment, however, this impairment is shown within Other in Note 14 - Business Segments due to acquisition adjustments at DPL which were not pushed down to the utility segment. In May 2014, an agreement was signed for the sale of DP&L’s interest in the generating assets at East Bend. This transaction closed on December 30, 2014.
Conesville (DP&L) - During the fourth quarter of 2013, DPL tested the recoverability of the long-lived assets at Conesville, a 129 MW coal-fired station in Ohio jointly-owned by DP&L. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit failing step 1 of the annual goodwill impairment test were determined to be an impairment indicator for long-lived assets. DPL performed a long-lived asset impairment test and determined that the carrying amount of the asset group was not recoverable. The long-lived asset group subject to the impairment evaluation was determined to be each individual station of
DP&L. This determination was based on the assessment of the stations’ ability to generate independent cash flows. The Conesville asset group was determined to have zero fair value using discounted cash flows under the income approach. As a result, DPL recognized an asset impairment expense of $26.2 million. Conesville is reported in the Utility segment.
Note 16 - Discontinued Operations
On January 1, 2016, DPL closed on the sale of DPLER, its competitive retail business. The sale agreement was signed on December 28, 2015 and DPL received $75.5 million of restricted cash on December 31, 2015 for the sale. This amount is shown as Restricted cash with the associated liability shown as "Deposit received on sale of DPLER" on the Balance Sheet as of December 31, 2015. As the cash received was restricted upon receipt, it is not included within the Statement of Cash Flows. Assets and liabilities related to DPLER have been reclassified to "Assets held for sale" and "Liabilities held for sale" in the December 31, 2015 and 2014 Balance Sheets. We expect to record a gain on this transaction of approximately $56.0 million, net of tax, in the first quarter of 2016. The gain includes the impact of deferred taxes and DPLER’s liability to DP&L that transferred with the sale on January 1, 2016 but was eliminated in consolidation at December 31, 2015 and 2014. Deferred taxes and intercompany balances were not reclassified to held for sale.
Operating activities related to DPLER have been reclassified to "Discontinued operations" in the Statements of Operations for the years ended December 31, 2015, 2014 and 2013.
The following table summarizes the major categories of assets, liabilities at the dates indicated, and the revenues, cost of revenues, operating expenses and income tax of discontinued operations for the periods indicated:
DPLER purchased its power from DP&L during the periods presented. Prior to DPLER being presented as a discontinued operation, this purchased power and DP&L's corresponding wholesale revenue would have been eliminated in consolidation.
Cash flows related to discontinued operations are included in our Consolidated Statements of Cash Flows. Cash flows from operating activities for discontinued operations were $35.8 million, $29.6 million and $(7.7) million for the years ended December 31, 2015, 2014 and 2013, respectively. Cash flows from investing activities for discontinued operations were $0.5 million, $(2.2) million and $(2.0) million for the years ended December 31, 2015, 2014, and 2013, respectively. All cash generated from discontinued operations was paid to DPL through dividends for all years presented.
FINANCIAL STATEMENTS
The Dayton Power and Light Company
Report of Independent Registered Public Accounting Firm
To the Board of Directors of The Dayton Power and Light Company
We have audited the accompanying balance sheets of The Dayton Power and Light Company (DP&L) as of December 31, 2015 and 2014, and the related statements of operations, comprehensive income, cash flows, and shareholder’s equity for each of the three years in the period ended December 31, 2015. Our audit also included the financial statement schedule “Schedule II - Valuation and Qualifying Accounts” for each of the three years in the period ended December 31, 2015. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DP&L at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
February 23, 2016
Indianapolis, Indiana
See Notes to Financial Statements.
See Notes to Financial Statements.
See Notes to Financial Statements.
See Notes to Financial Statements.
(a)
$0.01 par value, 250,000,000 shares authorized.
See Notes to Financial Statements.
The Dayton Power and Light Company
Notes to Financial Statements
For the years ended December 31, 2015, 2014 and 2013
Note 1 - Overview and Summary of Significant Accounting Policies
Description of Business
DP&L is a public utility incorporated in 1911 under the laws of Ohio. Beginning in 2001, Ohio law gave Ohio consumers the right to choose the electric generation supplier from whom they purchase retail generation service, however distribution and transmission services are still regulated. DP&L has the exclusive right to provide such service to its approximately 517,000 customers located in West Central Ohio. Additionally, DP&L procures and provides retail SSO electric service to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio and generates electricity at five coal-fired power stations. Beginning in 2014, DP&L no longer supplied 100% of the generation for SSO customers and starting January 2016, SSO is now 100% competitively bid. Principal industries located in DP&L’s service territory include automotive, food processing, paper, plastic, manufacturing and defense. DP&L's sales reflect the general economic conditions, seasonal weather patterns of the area and the market price of electricity. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sold electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.
In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets. On July 14, 2014, DP&L announced its decision to retain DP&L’s generation assets. On September 17, 2014 the PUCO ordered that DP&L’s application as amended and updated was approved. DP&L is required to sell or transfer its generation assets by January 1, 2017 and continues to look at multiple options to effectuate the separation, including transfer into an unregulated affiliate of DPL or through a sale.
DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators, while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.
DP&L employed 1,189 people at January 31, 2016. Approximately 61% of all employees are under a collective bargaining agreement which expires on October 31, 2017.
Financial Statement Presentation
DP&L does not have any subsidiaries. DP&L has undivided ownership interests in five electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements.
Certain immaterial amounts from prior periods have been reclassified to conform to the current period presentation.
The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.
Revenue Recognition
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of operations using an accrual method for retail and other energy sales that have not yet been billed, but where
electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.
All of the power produced at the generation stations is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. The power sales and purchases within DP&L’s service territory are reported on a net hourly basis as revenues or purchased power on our Statements of Operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.
Allowance for Uncollectible Accounts
We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collections efforts have been exhausted.
Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held stations as an asset in property, plant and equipment. New property, plant and equipment additions are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was $2.0 million, $1.5 million, and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.
For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.
For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization.
Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.
Repairs and Maintenance
Costs associated with maintenance activities, primarily power station outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.
Depreciation
Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DP&L’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 2.6% in 2015, 2.8% in 2014 and 4.4% in 2013. Depreciation was $132.7 million, $141.6 million and $136.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.
During the fourth quarter of 2015, DP&L tested the recoverability of long-lived assets at certain generating stations. See Note 13 - Fixed-asset Impairment for more information. Gradual decreases in power prices as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator.
Regulatory Accounting
As a regulated utility, we apply the provisions of FASC 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the PUCO and the FERC. Regulatory assets generally represent incurred
costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory assets have been included as allowable costs for ratemaking purposes, as authorized by the PUCO or established regulatory practices. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous over collections or the deferral of revenues collected for costs that DP&L expects to incur in the future.
The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the PUCO or FERC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Our regulatory assets and liabilities have been created pursuant to a specific order of the PUCO or FERC or established regulatory practices, such as other utilities under the jurisdiction of the PUCO or FERC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to PUCO or FERC approval. Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected. See Note 3 - Regulatory Assets and Liabilities for more information.
Inventories
Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.
Intangibles
Intangibles include 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.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. We establish an allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Our tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid within one year. Our policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Statement of Operations.
Income taxes payable, which are includable in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets with a corresponding deferred tax liability. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 3 - Regulatory Assets and Liabilities for additional information.
DPL and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 8 - Income Taxes for additional information.
Financial Instruments
We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost bases for public equity security and fixed maturity investments are average cost and amortized cost, respectively.
Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities
DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes and certain other taxes are accounted for on a net basis and recorded as a reduction in revenues in the accompanying Statements of Operations. The amounts for the years ended December 31, 2015, 2014 and 2013 were $49.9 million, $50.8 million and $50.5 million, respectively.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Restricted Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. At December 31, 2015, restricted cash also includes cash received in connection with the January 1, 2016 contract termination canceling DP&L's power sales contracts with DPLER. See Note 14 - Subsequent Event for additional information regarding this contract termination.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in fair value being recorded within accumulated other comprehensive income, a component of shareholder’s equity. We have elected not to offset net derivative positions in the financial statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 6 - Derivative Instruments and Hedging Activities for additional information.
Insurance and Claims Costs
In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, other DPL subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, and property damage on an ongoing basis. MVIC maintains an active run-off policy for directors’ and officers’ liability and fiduciary through their expiration in 2017, which may or may not be renewed at that time. DP&L is responsible for claim costs below certain coverage thresholds of MVIC and third party insurers for the insurance coverage noted above. DP&L has estimated liabilities for medical, life, and disability reserves for claims costs below certain coverage thresholds of MVIC and third-party providers. We recorded these additional insurance and claims costs of approximately $13.7 million and $15.6 million at December 31, 2015 and 2014, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The estimated liabilities for workers’ compensation, medical, life and disability costs at DP&L are actuarially determined using certain assumptions. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.
Pension and Postretirement Benefits
We recognize, in our Balance Sheets, an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status recognized in AOCI, except for those portions of our pension and postretirement obligations that can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postemployment benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postemployment plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.
Effective January 1, 2016, we will apply a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and post-retirement plans. This approach is consistent with the requirements of ASC 715 and is considered to be preferential to the aggregated single rate discount approach, which has historically been used in the U.S., because it is more consistent with the philosophy of a full yield curve valuation.
The change in discount rate approach did not have an impact on the measurement of the benefit obligations at December 31, 2015, nor will it impact future remeasurements. This change in approach will impact the service cost and interest cost recorded in 2016 and future years. It will also impact the actuarial gains and losses recorded in future years, as well as the amortization thereof.
The expected 2016 service costs and interest costs included in Note 9 - Benefit Plans reflect the change in methodology described above. The impact of the change in approach on expected service costs in 2016 is shown below:
See Note 9 - Benefit Plans for more information.
Related Party Transactions
In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL or AES.
See Note 12 - Related Party Transactions for additional information on Related Party Transactions.
New accounting pronouncements adopted
ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes
Effective December 31, 2015, we prospectively adopted ASU No. 2015-17, which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. The guidance does not change the existing requirement that only permits offsetting within a jurisdiction; that is, companies will remain prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. Additionally, the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the update. As we elected to apply this ASU prospectively, prior periods were not adjusted.
ASU No. 2015-13, Derivatives and Hedging (Topic 815):Derivatives and Hedging: Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Market
In August 2015, the FASB issued ASU No. 2015-13, which resolves the diversity in practice resulting from determining whether certain contracts qualify for the normal purchases and normal sales scope exception under ASC Topic 815, Derivatives and Hedging. This standard clarifies that entities would not be precluded from applying the normal purchases and normal sales exception to certain forward contracts that necessitate the transmission of electricity through, or delivery to a location within, a nodal energy market. The standard is effective upon issuance and should be applied prospectively. As we had designated qualifying contracts as normal purchase or normal sales, there was no impact on our financial statements upon adoption of this standard.
Accounting pronouncements issued but not yet effective
ASU No. 2016-01, Financial Instruments - Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, which was designed to improve the recognition and measurement of financial instruments through targeted changes to existing GAAP. The guidance requires equity investments (except those that are accounted for under the equity method of accounting or result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income; that entities use the exit price notion when measuring financial instrument fair values; that an entity separate presentation of financial assets and liabilities by measurement category and form of financial asset on the Balance Sheets or Notes to the financial statements; that an entity present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk (or "own credit") when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. Also, the standard eliminates the requirement for public entities to disclose the methods and significant assumptions used to estimate the fair value required to be disclosed for financial instruments measured at amortized cost on the Balance Sheets. The standard is effective beginning with interim periods starting after December 31, 2017 and cannot be applied early. We are currently evaluating the applicability and materiality of the standard, but we do not anticipate a material impact on our financial statements.
ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
In September 2015, the FASB issued ASU 2015-16, which simplifies the measurement-period adjustments in business combinations. It eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. An acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. The standard is effective for public entities for annual reporting periods beginning after December 15, 2015, and interim periods therein. Early adoption is permitted for financial statements that have not been issued. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this standard. We will adopt this standard on January 1, 2016, which is not expected to have a material impact on our
ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30)
In April 2015, the FASB issued ASU No. 2015-03, which simplifies the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein, and requires the use of the full retrospective approach. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015 DP&L had approximately $6.3 million in deferred financing costs classified in other current and other non-current assets that would be reclassified to reduce the related debt liabilities upon adoption of ASU No. 2015-03.
ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements
In August 2015, the FASB issued ASU No. 2015-15, which clarifies that the SEC Staff would not object to an entity presenting debt issuance costs related to line-of-credit arrangements as an asset that is subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This standard should be adopted concurrent with adoption of ASU 2015-03 (which is described above). As of December 31, 2015, we had deferred financing costs related to lines of credit of approximately $0.7 million recorded within Other noncurrent assets that would not be reclassified upon adoption of this standard.
ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory
In July 2015, the FASB issued ASU No. 2015-11, which simplifies the subsequent measurement of inventory. It replaces the current lower of cost or market test with a lower of cost or net realizable value test. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted. The new guidance must be applied prospectively. As we already used the net realizable value to make lower of cost or market determinations, there will be no impact on our financial statements upon adoption of this standard.
ASU No. 2015-05, Intangibles - Goodwill and Other: Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
In April 2015, the FASB issued ASU No. 2015-05, which clarifies how customers in cloud computing arrangements should determine whether the arrangement includes a software license and eliminates the existing requirement for customers to account for software licenses they acquired by analogizing to the accounting guidance on leases. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of a prospective or retrospective approach. As all of our cloud computing arrangements will continue to be accounted for as service agreements, there will be no impact on our financial statements upon the adoption of this standard.
ASU No. 2014-05, Presentation of Financial Statements: Going Concern
The FASB recently issued ASU 2014-15 “Presentation of Financial Statements - Going Concern (Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern)” effective for annual and interim periods ending after December 15, 2016. ASU 2014-15 requires management to evaluate whether there are conditions or events, considered in aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. There are required disclosures if substantial doubt is identified including documentation of: principal conditions or events that raised substantial doubt about the entity’s ability to continue as a going concern (before consideration of management’s plans), management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern. This ASU is not expected to have any impact on our overall results of operations, financial position or cash flows.
ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09, which clarifies principles for recognizing revenue and will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contract with Customers (Topic 606): Deferral of the Effective Date, which deferred the effective date of ASU 2014-09 by one year, resulting in the new revenue standard being effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. Early adoption is now permitted only as of the original effective date for public entities (that is, no earlier than 2017 for calendar year-end entities). The standard permits the use of either a full retrospective or modified retrospective approach. We have not yet selected a transition method and are currently evaluating the impact of adopting the standard on our financial statements.
ASU No. 2015-02, Consolidation - Amendments to the Consolidation Analysis (Topic 810)
In February 2015, the FASB issued ASU 2015-02, which makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the Variable Interest Entity (VIE) guidance. The standard amends the evaluation of whether (1) fees paid to a decision-maker or service providers represent a variable interest, (2) a limited partnership or similar entity has the characteristics of a VIE and (3) a reporting entity is the primary beneficiary of a VIE. The standard is effective for annual periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. We do not expect this standard to have an impact on our financial statements upon adoption.
Note 2 - Supplemental Financial Information
Accumulated Other Comprehensive Income (Loss)
The amounts reclassified out of Accumulated Other Comprehensive Income / (Loss) by component during the years ended December 31, 2015, 2014 and 2013 are as follows:
The changes in the components of Accumulated Other Comprehensive Income / (Loss) during the years ended December 31, 2015 and 2014 are as follows:
Note 3 - Regulatory Assets and Liabilities
In accordance with FASC 980, we have recognized total regulatory assets of $194.3 million and $211.7 million at December 31, 2015 and 2014, respectively, and total regulatory liabilities of $151.4 million and $128.5 million at December 31, 2015 and 2014, 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:
A - Recovery of incurred costs without a rate of return.
B - Recovery of incurred costs plus rate of return.
C - Balance has an offsetting liability resulting in no effect on rate base.
D - Recovery not yet determined, but is probable of occurring in future rate proceedings.
Regulatory assets
Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. As part of the PUCO approval process, an outside auditor reviews fuel costs and the fuel procurement process. The audit for 2014 is in process. The costs recovered through the fuel rider have decreased significantly over the past three years as more SSO supply is provided through the competitive bid. While no further fuel or purchased power costs will be recoverable through the rider, it will continue for up to six months to allow for recovery of the ending deferral amount.
Fuel costs - long-term represent unrecovered fuel costs related to DP&L’s fuel rider from 2010 through 2015 resulting from a declining SSO customer base. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Economic development costs represent costs incurred to promote economic development within the State of Ohio. These costs are being recovered through an Economic Development Rider that is subject to a bi-annual true-up process for any over/under recovery of costs.
Deferred storm costs represent costs incurred to repair the damage to DP&L’s distribution equipment by major storms in 2008, 2011 and 2012. All such costs have now been recovered.
Energy efficiency program costs represent costs incurred to develop and implement various customer programs addressing energy efficiency. These costs are being recovered through an Energy Efficiency Rider (EER) that began July 1, 2009 and that is subject to an annual true-up for any over/under recovery of costs. In addition to recovery of program costs, this rider has allowed for DP&L to recover lost margin associated with decreases in sales as a result of the programs implemented. The authority to recover lost margin included a maximum amount, which DP&L reached in the fourth quarter of 2015. Consequently, we discontinued accruing an asset for lost revenues after the maximum was reached. In addition, this rider provides that DP&L can earn a “shared savings” incentive that is tiered depending upon the level of success the programs reach. In 2014 and 2015, the maximum shared savings was accrued based upon performance, which is equal to $4.5 million per year, after income taxes.
Pension 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.
Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow-through items as the result of tax benefits previously provided to customers. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.
Unrecovered OVEC charges represent the portion of capacity charges from OVEC that were not recoverable through DP&L’s fuel rider beginning in October 2014. DP&L expects to recover these costs through a future rate proceeding.
Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.
Smart Grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and the implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities' Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate,
file new Smart Grid and/or AMI business cases in the future. This plan is currently under development and we plan to seek recover of these deferred costs in a regulatory rate proceeding in the near future. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.
Generation separation costs represent financing, redemption and other costs related to the divestiture of DP&L’s generation assets. The PUCO directed DP&L to divest its generation assets by January 1, 2017. DP&L requested and was granted permission by the PUCO to defer all financing, redemption and related costs it incurs to transfer its generation assets. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers with what its customers actually use. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Consumer education campaign represents costs for consumer education advertising regarding electric deregulation. DP&L has requested recovery of these costs as part of its pending distribution rate case filing.
Rate case costs represent costs associated with preparing a distribution rate case. DP&L has requested recovery of these costs as part of its pending Distribution Rate Case filing.
Regulatory liabilities
Energy efficiency program costs see “Regulatory Assets - Energy efficiency program costs” above.
Competitive bidding represents costs associated with the development and implementation of a Competitive Bidding Process, establishing contracts to supply power for a portion of DP&L’s Standard Service Offer load, as well as the net over/under recovery of the cost of the power purchased from the bid winners.
Transmission costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.
Reconciliation rider represents the costs that exceed 10 percent of the base amount of the following riders: Fuel, RPM, Alternative Energy and Competitive Bidding. This rider is in an overcollection position and will be discontinued after this overcollection has been refunded to customers.
Estimated costs of removal - regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.
Postretirement benefits represent the qualifying FASC 715 “Compensation - Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.
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, 2015 and 2014:
DP&L and certain other Ohio utilities have undivided ownership interests in five coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. At December 31, 2015, DP&L had $39.0 million of construction work in process at such facilities. DP&L’s share of the operations of such facilities is included within the corresponding line in the Statements of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly-owned station.
Coal-fired facilities
DP&L’s undivided ownership interest in such facilities at December 31, 2015, is as follows:
Each of the above generating units has SCR and FGD equipment installed.
Beckjord Unit 6 was retired effective October 1, 2014 and DP&L sold its interest in East Bend on December 30, 2014.
As part of the provisional DPL purchase accounting adjustments related to the Merger, four stations (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a fair market value different than DP&L’s carrying value. Since DP&L did not apply push down accounting, this valuation did not affect the carrying value of these stations’ valuation at DP&L. In the fourth quarter of 2013, DP&L performed an impairment review of its stations and recorded impairment expense of $86.0 million related to two of its stations, Conesville and East Bend. See Note 13 - Fixed-asset Impairment for more information on these impairments.
AROs
We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations are associated with the retirement of our long-lived assets, consisting primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within Other deferred credits on the consolidated balance sheets.
Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.
Changes in the Liability for Generation AROs
Asset Removal Costs
We continue to record cost of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $121.8 million and $119.3 million in estimated costs of removal at December 31, 2015 and 2014, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 - Regulatory Assets and Liabilities for additional information.
Changes in the Liability for Transmission and Distribution Asset Removal Costs
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, 2015 and 2014. See also Note 6 - Derivative Instruments and Hedging Activities for the fair values of our derivative instruments.
Fair value hierarchy
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as:
•
Level 1 (quoted prices in active markets for identical assets or liabilities);
•
Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); and
•
Level 3 (unobservable inputs).
Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.
We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2015 and 2014.
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 2016 to 2061.
Master trust assets
DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.
DP&L had $0.8 million ($0.5 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at December 31, 2015 and $1.1 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2014.
Various investments were sold during the past twelve months to facilitate the distribution of benefits. During the past twelve months, an immaterial amount of unrealized gains were reversed into earnings. Over the next twelve months, an immaterial amount of unrealized gains is expected to be reversed to earnings.
The fair value of assets and liabilities at December 31, 2015 and the respective category within the fair value hierarchy for DP&L was determined as follows:
(a)
Includes credit valuation adjustment.
The fair value of assets and liabilities at December 31, 2014 and the respective category within the fair value hierarchy for DP&L was determined as follows:
(a)
Includes credit valuation adjustment.
Our financial instruments are valued using the market approach in the following categories:
•
Level 1 inputs are used for derivative contracts, such as heating oil futures, and for money market accounts that are considered cash equivalents. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.
•
Level 2 inputs are used to value derivatives such as forward power contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit.
•
Level 3 inputs, such as financial transmission rights, are considered a Level 3 input because the monthly auctions are considered inactive. Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.
Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. The WPAFB note is not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.
Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.
Non-recurring Fair Value Measurements
We use the cost approach to determine the fair value of our AROs, which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. AROs for asbestos, ash ponds, underground storage tanks, and river structures increased by a net amount of $39.2 million ($25.5 million after tax) and $3.0 million ($2.0 million after tax) during the 12 months ended December 31, 2015 and 2014, respectively. The majority of the increase for 2015 is due to a net increase in the ARO for ash ponds of $40.3 million ($26.2 million after tax) as a result of new rules promulgated by the USEPA that were published in the Federal Register in April 2015 and became effective in October 2015. See Note 4 - Property, Plant and Equipment for more information about AROs.
When evaluating impairment of long-lived assets, we measure fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to the carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
(a)
See Note 13 - Fixed-asset Impairment for further information.
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the year ended December 31, 2013:
Note 6 - Derivative Instruments and Hedging Activities
In the normal course of business, DP&L enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under FASC 815 for accounting purposes.
At December 31, 2015, DP&L had the following outstanding derivative instruments:
At December 31, 2014, DP&L had the following outstanding derivative instruments:
Cash flow hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.
We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.
The following tables set forth the gains / (losses) recognized in AOCI and earnings related to the effective portion of derivative instruments and the gains / (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:
(a)
The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.
Derivatives not designated as hedges
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting”. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures and certain forward power contracts.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of results of operations on an accrual basis.
Regulatory assets and liabilities
In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a
regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.
The following tables show the amount and classification within the statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the years ended December 31, 2015, 2014 and 2013.
The following tables show the fair value, balance sheet classification and hedging designation of DP&L’s derivative instruments at December 31, 2015 and 2014.
Credit risk-related contingent features
Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. Since our debt has fallen below investment grade, we are in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. Some of our counterparties to the derivative instruments have requested collateralization of the MTM loss.
The aggregate fair value of DP&L’s derivative instruments that are in a MTM loss position at December 31, 2015 is $27.5 million. This amount is offset by $8.0 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by
the asset position of counterparties with master netting agreements of $17.9 million. If DP&L debt were to fall below investment grade, DP&L could be required to post collateral for the remaining $1.6 million.
Note 7 - Debt
Long-term debt is as follows:
At December 31, 2015, maturities of long-term debt are summarized as follows:
Significant transactions
On December 31, 2015, DP&L borrowed $35.0 million from DPL at an interest rate of 2.67%. The notes were due on or before December 31, 2016 and were repaid on January 29, 2016.
On July 1, 2015, the $35.3 million of DP&L's 4.7% pollution control bonds due January 2028 and $41.3 million of DP&L's 4.8% pollution control bonds due January of 2034 were called at par and were redeemed with cash.
On July 31, 2015, DP&L refinanced its revolving credit facility. The new facility has a $175.0 million borrowing limit, a $50.0 million letter of credit sublimit, a feature that provides DP&L the ability to increase the size of the facility by an additional $100.0 million and a maturity date of July 2020. At December 31, 2015, there were two letters of credit in the amount of $1.4 million outstanding, with the remaining $173.6 million available to DP&L. Fees associated with this revolving credit facility were not material during the years ended December 31, 2015 or 2014. Prior to refinancing the facility on July 31, 2015, this facility had a $300.0 million borrowing limit, a five-year term expiring on May 10, 2018, a $100.0 million letter of credit sublimit and a feature that provided DP&L the ability to increase the size of the facility by an additional $100.0 million.
On August 3, 2015, DP&L called $100.0 million of variable rate pollution control bonds due November 2040, terminated the amended standby letter of credit facilities that supported these pollution control bonds, and called $137.8 million of 4.8% pollution control bonds due January of 2034. DP&L also used cash to redeem $37.8 million of these bonds and refinanced the $200.0 million balance, with new variable interest rate pollution control bonds secured by first mortgage bonds in an equivalent amount. In connection with the sale of the new pollution control bonds, DP&L entered into a certain Bond Purchase and Covenants Agreement, dated as of August 1, 2015, containing representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L.
On March 31, 2014, DP&L borrowed $15.0 million from DPL at an interest rate of LIBOR plus 2.0%. This note was due on or before April 30, 2014 and was repaid on April 30, 2014.
On September 19, 2013, DP&L closed a $445.0 million issuance of senior secured first mortgage bonds. These new bonds mature on September 15, 2016, and are secured by DP&L’s First & Refunding Mortgage. Substantially all property, plant and equipment of DP&L is subject to the lien of the First and Refunding Mortgage. Substantially concurrent with this transaction, DP&L redeemed $470.0 million of previously outstanding first mortgage bonds.
Debt covenants and restrictions
In connection with DP&L’s sale of $200.0 million of variable rate pollution control bonds dated August 1, 2015, DP&L entered into an unsecured revolving credit agreement and a Bond Purchase and Covenants Agreement. These agreements contain representations, warranties, covenants and defaults consistent with those contained in the revolving credit facilities loan documents of DP&L and have two financial covenants. The first measures Total Debt to Total Capitalization and is calculated, at the end of each fiscal quarter, by dividing total debt at the end of the quarter by total capitalization at the end of the quarter. The second financial covenant measures EBITDA to Interest Expense. The EBITDA to Interest Expense ratio is calculated, at the end of each fiscal quarter, by dividing EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.
As of December 31, 2015, DP&L was in compliance with all debt covenants, including the financial covenants described above and did not have any meaningful restrictions in its debt financing documents prohibiting dividends to its parent, DPL.
Note 8 - Income Taxes
DP&L’s components of income tax expense were as follows:
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, 2015, 2014 and 2013:
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.
(a)
The statutory tax rate of 35% was applied to pre-tax earnings.
(b)
Includes benefit of $0.4 million, expense of $0.7 million and benefit of $1.1 million in the years ended December 31, 2015, 2014 and 2013, respectively, of income tax related to adjustments from prior years.
(c)
Amounts are included within Other prepayments and current assets and Other current liabilities on the Balance Sheets of DP&L.
The following table presents the tax (benefit) / expense related to pensions, postemployment benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.
Uncertain Tax Positions
We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DP&L is as follows:
Of the December 31, 2015 balance of unrecognized tax benefits, $0.9 million is due to uncertainty in the timing of deductibility.
We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amounts accrued and expense (benefit) recorded were not material for each period presented.
Following is a summary of the tax years open to examination by major tax jurisdiction:
U.S. Federal - 2010 and forward
State and Local - 2010 and forward
None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months other than those subject to expiring statute of limitations.
The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010. The results of the examination were approved by the Joint Committee on Taxation on January 18, 2013. As a result of the examination, DPL received a refund of $19.9 million and recorded a $1.2 million reduction to income tax expense in 2013.
Note 9 - Benefit Plans
Defined contribution plans
DP&L sponsors two defined contribution plans. One is for non-union employees (the management plan) and one is for collective bargaining employees (the union plan). Both plans are qualified under Section 401 of the Internal Revenue Code.
Certain non-union employees become eligible to participate in the management plan on the first day of the month following the first full calendar month of employment; provided the employee worked at least 160 hours in that calendar month. Union employees become eligible to participate in the union plan on the first day of the first month following 30 days of employment. Effective January 1, 2016, employees in both plans are eligible to participate upon date of hire.
Participants may elect to contribute up to 85% of eligible compensation to their plan. Non-union participant contributions are matched 100% on the first 1% of eligible compensation and 50% on the next 5% of eligible compensation and they are fully vested in their employer contributions after 2 years of service. Union participant contributions are matched 150% but are capped at $2,100 for 2015 and they are fully vested in their employer contributions after 3 years of service. All participants are fully vested in their own contributions.
For the years ended December 31, 2015, 2014 and 2013 DP&L's contributions to all defined contribution plans were $4.8 million, $4.7 million and $4.8 million per year, respectively.
Defined benefit plans
DP&L sponsors a traditional defined benefit pension plan for most of the employees of DPL and its subsidiaries. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the traditional defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this traditional pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Effective January 1, 2014, the Service Company began providing services including accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including among other companies, DPL and DP&L. Employees that transferred from DP&L to the Service Company maintain their previous eligibility to participate in the DP&L pension plan.
Almost all management employees beginning employment on or after January 1, 2011 participate in a cash balance pension plan. Similar to the traditional pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.
In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain retired key executives. The SERP has an immaterial unfunded liability related to agreements for retirement benefits of certain terminated and
retired key executives. We also include our net liability to our partners related to our share of their pension costs within Pension, retiree and other benefits on our Balance Sheets.
We recognize an asset for a plan’s overfunded status and a liability for a plan’s underfunded status and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. For the transmission and distribution areas of our electric business, these amounts are recorded as regulatory assets and liabilities which represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered through customer rates. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.
Postretirement benefits
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.
The following tables set forth the changes in our pension and postemployment benefit plans’ obligations and assets recorded on the balance sheets at December 31, 2015 and 2014. The amounts presented in the following tables for pension obligations include the collective bargaining plan formula, traditional management plan formula and cash balance plan formula and the SERP in the aggregate. The amounts presented for postemployment obligations include both health and life insurance benefits.
The accumulated benefit obligation for our defined benefit pension plans was $401.2 million and $431.0 million at December 31, 2015 and 2014, respectively.
The net periodic benefit cost of the pension and postretirement plans were:
Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities
Estimated amounts that will be amortized from AOCI, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2016 are:
Assumptions
Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.
At December 31, 2015, we are maintaining our long term rate of return assumption of 6.50% for pension plan assets. In addition, we are decreasing our long-term rate of return assumption to 3.90% from 4.50% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our long-term portfolio mixes. Also, at December 31, 2015, we have increased our assumed discount rate to 4.49% from 4.02% for pension and to 4.10% from 3.71% for postemployment benefits expense to reflect current duration-based yield curve discount rates. A one percent increase in the rate of return assumption for pension would result in a decrease in pension expense of approximately $3.5 million. A 1% decrease in the rate of return assumption for pension would result in an increase in pension expense of approximately $3.5 million. A 25 basis point increase in the discount rate for pension would result in a decrease of approximately $0.2 million to 2016 pension expense. A 25 basis point decrease in the discount rate for pension would result in an increase of approximately $0.3 million to 2016 pension expense. A one percent change in the assumed health care cost trend rate would affect postemployment benefit costs by less than $1.0 million.
In determining the discount rate to use for valuing liabilities, we used a market yield curve on high-quality fixed income investments as of December 31, 2015. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are then discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.
Effective January 1, 2016 we will apply the spot rate approach for determining service cost and interest cost for its defined benefit pension plans and other post-retirement plan. The expected 2016 service costs and interest costs included above reflect the change in methodology. The impact of the change in approach is a reduction in: (1) expected service costs of $0.4 million for pension plans in 2016 ($0.4 million Defined Benefit Pension Plan and $0.0 million Supplemental Retirement Plan), and (2) expected interest costs of $3.2 million for pension plans in 2016 ($3.1 million Defined Benefit Pension Plan and $0.1 million Supplemental Retirement Plan).
The weighted average assumptions used to determine benefit obligations during the years ended December 31, 2015, 2014 and 2013 were:
The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2015, 2014 and 2013 were:
The assumed health care cost trend rates at December 31, 2015, 2014 and 2013 are as follows:
The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postemployment benefit cost and the accumulated postemployment benefit obligation:
Pension plan assets
Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan's funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.
Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of plan equity investments is to maximize the long-term real growth of plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of plan equity investments.
Long-term strategic asset allocation guidelines, as well as short-term tactical asset allocation guidelines, are determined by a Risk/Advisory Committee and approved by a Fiduciary Committee. These allocations take into account the Plan’s long-term objectives. The long-term target allocations for plan assets are 18% - 38% for equity securities and 58% - 86% 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 allocation to a core property fund, as well as a small allocation to a hedge 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 and the Common collective fund are measured using Level Two inputs that are quoted prices for identical assets in markets that are less active.
The following table summarizes our target pension plan allocation for 2015:
The fair values of our pension plan assets at December 31, 2015 by asset category are as follows:
(a)
This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
The fair values of our pension plan assets at December 31, 2014 by asset category are as follows:
(a)
This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(b)
This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
(c)
This category comprises cash held to pay beneficiaries. The fair value of cash equals its book value.
(d)
This category represents a property fund that invests in commercial real estate and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.
The fair values of our other postemployment benefit plan assets at December 31, 2015 by asset category are as follows:
(a)
This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.
The fair values of our other postemployment benefit plan assets at December 31, 2014 by asset category are as follows:
(a)
This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities.
Pension funding
We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. We contributed $5.0 million, $0.0 million, and $0.0 million during the years ended December 31, 2015, 2014 and 2013, respectively.
We expect to make contributions of $0.4 million to our SERP in 2016 to cover benefit payments. We also expect to contribute $1.1 million to our other postemployment benefit plans in 2016 to cover benefit payments. We made contributions of $5.0 million to our pension plan during January, 2016.
The Pension Protection Act of 2006 (the Act) contained new requirements for our single employer defined benefit pension plan. In addition to establishing a 100% funding target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2015 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 112.54% and is estimated to be 112.54% until the 2016 status is certified in September 2016 for the 2016 plan year. The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, grants plan sponsors certain relief from funding requirements and benefit restrictions of the Act.
Benefit payments, which reflect future service, are expected to be paid as follows:
Note 10 - Equity
Redeemable Preferred Stock
DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 were outstanding at December 31, 2015. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding at December 31, 2015. The table below details the preferred shares outstanding at December 31, 2015 and 2014:
The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends, of which there were none at December 31, 2015. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.
Dividend Restrictions
As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not impacted DP&L’s ability to pay cash dividends and, as of December 31, 2015, DP&L’s retained earnings of 437.3 million were all available for common stock dividends payable to DPL. We do not expect this restriction to have an effect on the payment of cash dividends in the future.
Common Stock
DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at December 31, 2015. All common shares are held by DP&L’s parent, DPL.
As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance.
Note 11 - Contractual Obligations, Commercial Commitments and Contingencies
DP&L - Equity Ownership Interest
DP&L has a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. At December 31, 2015, DP&L could be responsible for the repayment of 4.9%, or $74.5 million, of a $1,519.9 million debt obligation comprised of both fixed and variable rate securities with maturities between 2016 and 2040. This would only happen if this electric generation company defaulted on its debt payments. At December 31, 2015, we have no knowledge of such a default.
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2015, these include:
(a)
Total at DP&L operated units.
Coal contracts:
DP&L has entered into various long-term coal contracts to supply the coal requirements for the generating stations it operates. At December 31, 2015, 73% of our future committed coal obligations are with a single supplier. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.
Purchase orders and other contractual obligations:
At December 31, 2015, DP&L had various other contractual obligations, including non-cancelable contracts, to purchase goods and services with various terms and expiration dates.
Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2015, cannot be reasonably determined.
Environmental Matters
DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may affect us include:
•
The federal CAA and state laws and regulations (including SIPs) which require compliance, obtaining permits and reporting as to air emissions,
•
Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating stations require additional permitting or pollution control technology, or whether emissions from coal-fired generating stations cause or contribute to global climate changes,
•
Rules and future rules issued by the USEPA and the Ohio EPA that require substantial reductions in SO2, particulates, mercury, acid gases, NOX, and other air emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions,
•
Rules and future rules issued by the USEPA and the Ohio EPA that require reporting and reductions of GHGs,
•
Rules and future rules issued by the USEPA associated with the federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and
•
Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at our facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have accruals for loss contingencies of approximately $0.9 million for environmental matters. We also have a number of environmental matters for which we have not accrued loss contingencies because the risk of loss is not probable or a loss cannot be reasonably estimated. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.
We have several pending environmental matters associated with our coal-fired generation units. Some of these matters could have material adverse impacts on the operation of the power stations.
Note 12 - Related Party Transactions
In December 2013, an agreement was signed, effective January 1, 2014, whereby the Service Company began providing services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the U.S. SBU, including, among other companies, DPL and DP&L. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including DP&L, are not subsidizing costs incurred for the benefit of other businesses.
The following table provides a summary of these transactions:
(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 paid by DP&L to MVIC.
(c)
In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include but are not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded.
(d)
DP&L requires credit assurance from the CRES providers serving customers in its service territory because DP&L is the default energy provider should the CRES provider fail to fulfill its obligations to provide electricity. Due to DPL’s credit downgrade, DP&L required cash collateral from DPLER.
Income taxes
AES files federal and state income tax returns which consolidate DPL and its subsidiaries, including DP&L. Under a tax sharing agreement with DPL, DP&L is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. DP&L had a net receivable balance under this agreement of $1.5 million and $1.0 million as of December 31, 2015 and 2014, respectively, which is recorded in Other current assets on the accompanying Balance Sheets.
Note 13 - Fixed-asset Impairment
East Bend and Conesville - During the fourth quarter of 2013, DP&L tested the recoverability of long-lived assets at Conesville, a 129 MW coal-fired station in Ohio, and East Bend, a 186 MW coal-fired station in Kentucky jointly-owned by DP&L. Gradual decreases in power prices, as well as lower estimates of future capacity prices in conjunction with the DP&L reporting unit of DPL failing step 1 of the annual goodwill impairment test were collectively determined to be an impairment indicator for the DP&L long-lived assets. DP&L performed a long-lived asset impairment test and determined that the carrying amounts of the asset groups were not recoverable. The long-lived asset group subject to the impairment evaluation was determined to be each individual station of DP&L. This determination was based on the assessment of the stations’ ability to generate independent cash flows. The Conesville and East Bend asset groups were each determined to have a zero fair value using discounted cash flows under the income approach. As a result, DP&L recognized an asset impairment expense of $10.0 million and $76.0 million for Conesville and East Bend, respectively.
Note 14 - Subsequent Event
On January 1, 2016, DPL closed on the sale of DPLER to IGS. Also on January 1, 2016, DP&L terminated the contract it had with DPLER for the supply of electricity. The agreement terminating the contract was signed on December 28, 2015 and DP&L received $27.7 million of restricted cash on December 31, 2015 for the early termination of the contract, which we expect to record as a gain in the first quarter of 2016. This amount is shown as Restricted cash with the associated liability shown as Advance on contract termination on the Balance Sheet as of December 31, 2015. As the cash we received was restricted upon receipt it is not shown on the Statement of Cash Flows.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A
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 the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.
We carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2015, 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, 2015. 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, 2015.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B
Item 9B - Other Information
None.
PART III
Item 10
Item 10 - Directors, Executive Officers and Corporate Governance
Not applicable pursuant to General Instruction I of the Form 10-K.
Item 11
Item 11 - Executive Compensation
Not applicable pursuant to General Instruction I of the Form 10-K.
Item 12
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
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Not applicable pursuant to General Instruction I of the Form 10-K.
Item 14
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, 2015 and 2014. Other than as set forth below, no professional services were rendered or fees billed by Ernst & Young LLP during the years ended December 31, 2015 and 2014.
(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.
(c)
Tax fees consisted principally of tax compliance 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
Item 15 - Exhibits, Financial Statements and Financial Statement Schedules
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:
Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, we have not filed as an exhibit to 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.
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 23, 2016
/s/ Kenneth J. Zagzebski
Kenneth J. Zagzebski
President and Chief Executive Officer
(principal executive officer)
The Dayton Power and Light Company
February 23, 2016
/s/ Thomas A. Raga
Thomas A. Raga
President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of DPL Inc. and in the capacities and on the dates indicated.
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.
Schedule II
(a)
Amounts written off, net of recoveries of accounts previously written off.