DPL 10-K 2012
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
All of the outstanding common stock of DPL Inc. is indirectly owned by The AES Corporation. All of the common stock of The Dayton Power and Light Company is owned by DPL Inc.
As of December 31, 2011, each registrant had the following shares of common stock outstanding:
Documents Incorporated by Reference: None
This combined Form 10-K is separately filed by DPL Inc. and The Dayton Power and Light Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.
THE REGISTRANTS MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.
DPL Inc. and The Dayton Power and Light Company
Fiscal Year Ended December 31, 2011
The following select abbreviations or acronyms are used in this Form 10-K:
GLOSSARY OF TERMS (cont.)
GLOSSARY OF TERMS (cont.)
This report includes the combined filing of DPL and DP&L. On November 28, 2011, DPL became a wholly-owned subsidiary of AES, a global power company. Throughout this report, the terms we, us, our and ours are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.
FORWARD LOOKING STATEMENTS
Certain statements contained in this report are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including managements expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on managements beliefs, assumptions and expectations of future economic performance, taking into account the information currently available to management. These statements are not statements of historical fact and are typically identified by terms and phrases such as anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will and similar expressions. Such forward-looking statements are subject to risks and uncertainties and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to: abnormal or severe weather and catastrophic weather-related damage; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, natural gas and other commodity prices; volatility and changes in markets for electricity and other energy-related commodities; performance of our suppliers; increased competition and deregulation in the electric utility industry; increased competition in the retail generation market; changes in interest rates; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws; changes in environmental laws and regulations to which DPL and its subsidiaries are subject; the development and operation of RTOs, including PJM to which DPLs operating subsidiary (DP&L) has given control of its transmission functions; changes in our purchasing processes, pricing, delays, contractor and supplier performance and availability; significant delays associated with large construction projects; growth in our service territory and changes in demand and demographic patterns; changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; financial market conditions; the outcomes of litigation and regulatory investigations, proceedings or inquiries; general economic conditions; costs related to the Merger and the effects of any disruption from the Merger that may make it more difficult to maintain relationships with employees, customers, other business partners or government entities; and the risks and other factors discussed in this report and other DPL and DP&L filings with the SEC.
Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.
DPLs public internet site is http://www.dplinc.com. DP&Ls public internet site is http://www.dpandl.com. The information on these websites is not incorporated by reference into this report.
DPL is a regional energy company organized in 1985 under the laws of Ohio. Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio 45432 telephone (937) 224-6000. DPL was acquired by The AES Corporation on November 28, 2011 and is a wholly-owned, indirect subsidiary of AES.
DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&Ls 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic, manufacturing and defense. DP&Ls sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.
DPLER sells competitive retail electric service, under contract, to residential, commercial, industrial and governmental customers. DPLERs operations include those of its wholly-owned subsidiary, MC Squared, which was purchased on February 28, 2011. DPLER has approximately 40,000 customers currently located throughout Ohio and Illinois. DPLER does not have any transmission or generation assets and all of DPLERs electric energy was purchased from DP&L or PJM to meet its sales obligations.
DPLs other significant subsidiaries include: DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, DPLs captive insurance company that provides insurance services to us and DPLs other subsidiaries.
DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
All of DPLs subsidiaries are wholly-owned. DP&L does not have any subsidiaries.
DP&Ls 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 recoveries in customer rates relate to expected future costs.
DPL and its subsidiaries had 1,510 employees as of December 31, 2011, of which 1,338 were full-time and 172 were part-time. At that date, 1,297 of these full-time employees and substantially all of the part-time employees were employed by DP&L. Approximately 53% of the employees are under a collective bargaining agreement which expires on October 31, 2014.
ELECTRIC OPERATIONS AND FUEL SUPPLY
DPLs present summer generating capacity, including peaking units, is approximately 3,818 MW. Of this capacity, approximately 2,830 MW, or 74%, is derived from coal-fired steam generating stations and the balance of approximately 988 MW, or 26%, consists of solar, combustion turbine and diesel peaking units.
DP&Ls present summer generating capacity, including peaking units, is approximately 3,262 MW. Of this capacity, approximately 2,830 MW, or 87%, is derived from coal-fired steam generating stations and the balance of approximately 432 MW, or 13%, consists of solar, combustion turbine and diesel peaking units.
Our all-time net peak load was 3,270 MW, occurring August 8, 2007.
Approximately 87% of the existing steam generating capacity is provided by certain generating units owned as tenants in common with Duke Energy and CSP. As tenants in common, each company owns a specified share of each of these units, is entitled to its share of capacity and energy output and has a capital and operating cost responsibility proportionate to its ownership share. DP&Ls remaining steam generating capacity (approximately 365 MW) is derived from a generating station owned solely by DP&L. Additionally, DP&L, Duke Energy and CSP own, as tenants in common, 880 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.
In 2011, we generated 98.3% of our electric output from coal-fired units and 1.7% from solar, oil and natural gas-fired units.
The following table sets forth DP&Ls and DPLEs generating stations and, where indicated, those stations which DP&L owns as tenants in common.
*W = Wholly-Owned
C = Commonly-Owned
In addition to the above, DP&L also owns a 4.9% equity ownership interest in OVEC, an electric generating company. OVEC has two plants located in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,265 MW. DP&Ls share of this generation capacity is approximately 111 MW.
We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2012 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 outages and generation plant 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 a balanced SO2 and NOx position for 2012.
The gross average cost of fuel consumed per kWh was as follows:
The power generation and delivery business is seasonal and weather patterns have a material effect on operating performance. In the region we serve, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Unusually mild summers and winters could have an adverse effect on our results of operations, financial condition and cash flows.
RATE REGULATION AND GOVERNMENT LEGISLATION
DP&Ls sales to SSO retail customers are subject to rate regulation by the PUCO. DP&Ls transmission rates and wholesale electric rates to municipal corporations, rural electric co-operatives and other distributors of electric energy are subject to regulation by the FERC under the Federal Power Act.
Ohio law establishes the process for determining SSO retail rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate increases, the recoverable cost basis upon which the rates are set and other related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.
Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCOs supervisory powers to a holding company systems general condition and capitalization, among other matters, to the extent that such matters relate to the costs associated with the provision of public utility service. Based on existing PUCO and FERC authorization, regulatory assets and liabilities are recorded on the balance sheets. See Note 4 of Notes to DPLs Consolidated Financial Statements and Note 4 of Notes to DP&Ls Financial Statements.
COMPETITION AND REGULATION
Ohio Retail Rates
The PUCO maintains jurisdiction over DP&Ls delivery of electricity, SSO and other retail electric services.
On May 1, 2008, substitute SB 221, an Ohio electric energy bill, was signed by the Governor and went into effect July 31, 2008. This law required that all Ohio distribution utilities file either an ESP or MRO to establish rates for SSO service. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for cost-based adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade, or replace its electric distribution system, including cost recovery mechanisms. Both the MRO and ESP option involve a significantly excessive earnings test based on the earnings of comparable companies with similar business and financial risks. DP&Ls current SSO rates were established under an ESP that ends December 31, 2012. DP&L is in the process of developing an SSO filing that will be the basis for rates effective January 1, 2013 using either an ESP or MRO case. This case is scheduled to be filed on March 30, 2012.
SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. DP&L is currently meeting its renewable requirements and expects to remain in compliance. The PUCO found that both DP&L and DPLER met the renewable targets in 2009, and the PUCO Staff recommended that the Commission find that they both met the renewable targets for 2010.
On May 19, 2010 the Commission approved in part and denied in part DP&Ls request that the PUCO find that it met the 2009 energy efficiency portfolio requirements and directed DP&L to file a measurement and verification plan as well as a market potential study. We made this filing and settled the case through a stipulation that was approved in April 2011. The next energy efficiency portfolio plan is due to be filed in April 2013.
We are unable to predict how the PUCO will respond to many of the filings discussed above, but believe that the outcome for the non-ESP/MRO filings will not be material to our financial condition or results of operations. However, as the energy efficiency and alternative energy targets get increasingly larger over time, the costs of complying with SB 221 and the PUCOs implementing rules or the results of our ESP/MRO filing on March 30, 2012 could have a material effect on our financial condition or results of operations.
The ESP Stipulation also provided for the establishment of a fuel and purchased power recovery rider beginning January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter: March 1, June 1, September 1 and December 1 each year. As part of the PUCO approval process, an outside auditor was hired in 2011 to review fuel costs and the fuel procurement process for 2010. DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation which was approved by the PUCO on November 9, 2011. In November 2011, DP&L recorded a $25 million pretax ($16 million net of tax) adjustment as a result of the approval of the fuel settlement agreement by the PUCO. The adjustment was due to the reversal of a provision recorded in accordance with the regulatory accounting rules. An audit of 2011 fuel costs is currently ongoing. The outcome of that audit is uncertain.
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. SB 221 included a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. DP&Ls TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs. Both the TCRR and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of SSO retail customers load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching to CRES providers decreases DP&Ls SSO retail customers load and sales volumes. Therefore, increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. RPM capacity costs and revenues are discussed further under Regional Transmission Organizational Risks in Item 1A Risk Factors. DP&Ls annual true-up of these two riders was approved by the PUCO by an order dated April 27, 2011 and its 2012 filing is still pending.
On September 9, 2009, the PUCO issued an order establishing a significantly excessive earnings test (SEET) proceeding pursuant to provisions contained in SB 221. A question and answer session was held before the Commission on April 1, 2010 to allow the Commission to gain a better understanding of the issues. The PUCO issued an order on June 30, 2010 to establish general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. The other three Ohio utilities were required to make their SEET determinations in 2011 and 2010. Pursuant to the ESP Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and the SEET may have a material effect on operations.
On August 28, 2009, DP&L filed its application to establish reliability targets consistent with the most recent PUCO Electric Service and Safety Standards (ESSS). On March 29, 2010, DP&L entered into a settlement establishing the new reliability targets. This settlement was approved on July 29, 2010. According to the ESSS rules, all Ohio utilities are subject to financial penalties if the established targets are not met for two consecutive years.
Ohio Competitive Considerations and Proceedings
Since January 2001, DP&Ls 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 supply retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&Ls delivery of electricity, SSO and other retail electric services.
Market prices for power, as well as government aggregation initiatives within DP&Ls service territory, have led and may continue to lead to the entrance of additional competitors in our service territory. At December 31, 2011, there were fourteen CRES providers in DP&Ls service territory. DPLER, an affiliated company and one of the fourteen registered CRES providers, has been marketing supply services to DP&L customers. During 2011, DPLER accounted for approximately 5,731 million kWh of the total 6,593 million kWh supplied by CRES providers within DP&Ls service territory. Also during 2011, 27,812 customers with an annual energy usage of 862 million kWh were supplied by other CRES providers within DP&Ls service territory. The volume supplied by DPLER represents approximately 41% of DP&Ls total distribution sales volume during 2011. The reduction to gross margin in 2011 as a result of customers switching to DPLER and other CRES providers was approximately $58 million and $104 million, for DPL and DP&L, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.
Several communities in DP&Ls service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, nine organizations have filed with the PUCO to initiate aggregation programs. If these nine organizations move forward with aggregation, it could have a material effect on our earnings. See Item 1A Risk Factors for more information.
In 2010, DPLER began providing CRES services to business customers in Ohio who are not in DP&Ls service territory. The incremental costs and revenues have not had a material effect on our results of operations, financial condition or cash flows.
DP&L entered into an economic development arrangement with its single largest electricity consumer. This arrangement was approved by the PUCO on June 8, 2011 and became effective in July 2011. Under Ohio law, DP&L is permitted to seek recovery of costs associated with economic development programs including foregone revenues from all customers. On October 26, 2011, the PUCO approved our Economic Development Rider, as filed, which is designed to recover costs associated with this and other economic development contracts and programs.
Like other electric utilities and energy marketers, DP&L and DPLE may sell or purchase electric products on the wholesale market. DP&L and DPLE compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of DP&L and DPLE to sell this electricity will depend not only on the performance of our generating units, but also on how DP&Ls and DPLEs prices, terms and conditions compare to those of other suppliers.
As part of Ohios electric deregulation law, all of the states investor-owned utilities are required to join a RTO. In October 2004, DP&L successfully integrated its high-voltage transmission lines into the PJM RTO. The role of the RTO is to administer a competitive wholesale market for electricity and ensure reliability of the transmission grid. PJM ensures the reliability of the high-voltage electric power system serving more than 50 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the regions transmission grid, administers the worlds largest competitive wholesale electricity market and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.
The PJM RPM capacity base residual auction for the 2014/2015 period cleared at a per megawatt price of $126/day for our RTO area. The per megawatt prices for the periods 2013/2014, 2012/2013 and 2011/2012 were $28/day, $16/day and $110/day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJMs business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. Increases in customer switching causes more of the RPM capacity
costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but if the current auction price is not sustained, our future results of operations, financial condition and cash flows could be materially adversely impacted.
As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC orders issued in 2007 and thereafter regarding the allocation of costs of large transmission facilities within PJM which would result in additional costs being allocated to DP&L that, over time and depending on final costs and how quickly the facilities are constructed, could become material. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit, which was consolidated with other taken by other interested parties of the same FERC orders and the consolidated cases were assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. Rehearings were filed by other interested litigants and denied by the Court, which then remanded the matter to the FERC for further proceedings. On January 21, 2010, the FERC issued a procedural order on remand establishing a paper hearing process under which PJM will make an informational filing. Subsequently, PJM and other parties, including DP&L, filed initial comments, testimony and recommendations and reply comments. FERC did not establish a deadline for its issuance of a substantive order and the matter is still pending. DP&L cannot predict the timing or the likely outcome of the proceeding. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. Although we continue to maintain that these costs should be borne by the beneficiaries of these projects and that DP&L is not one of these beneficiaries, any new credits or additional costs resulting from the ultimate outcome of this proceeding will be reflected in DP&Ls TCRR rider which already includes these costs.
NERC is a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, including Critical Infrastructure Protection (CIP) reliability standards, across eight reliability regions. In June 2009, Reliability First Corporation (RFC), with responsibilities assigned to it by NERC over the reliability region that includes DP&L, commenced a routine audit of DP&Ls operations. The audit, which was for the period June 18, 2007 to June 25, 2009, evaluated DP&Ls compliance with 42 requirements in 18 NERC-reliability standards. DP&L is currently subject to a compliance audit at a minimum of once every three years as provided by the NERC Rules of Procedure. This audit was concluded in June 2009 and its findings revealed that DP&L had some Possible Alleged Violations (PAVs) associated with five NERC reliability requirements of various Standards. In response to the report, DP&L filed mitigation plans with RFC/NERC to address the PAVs. These mitigation plans were accepted by RFC/NERC. In July 2010, DP&L negotiated a settlement with NERC under which DP&L agreed to pay an immaterial amount in exchange for a resolution of all issues and obligations relating to the aforementioned PAVs. The settlement was approved on January 21, 2011 by the FERC.
DPLs and DP&Ls facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. The environmental issues that may effect us include:
· The Federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions.
· Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants require additional permitting or pollution control technology, or whether emissions from coal-fired generating plants cause or contribute to global climate changes.
· Rules and future rules issued by the USEPA and 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 Ohio EPA that require reporting and may require 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.
· 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. The EPA has previously determined that fly ash and other coal
combustion byproducts are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the EPA is reconsidering that determination. A change in determination or other additional regulation of fly ash or other coal combustion byproducts could significantly increase the costs of disposing of such ash byproducts.
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 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 estimated accruals for loss contingencies of approximately $3.4 million for environmental matters. We also have a number of unrecognized loss contingencies related to environmental matters that are disclosed in the paragraphs below. 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 other pending environmental matters associated with our coal-fired generation units. Together, these could result in significant capital and operations and maintenance expenditures for our coal-fired generation plants, and could result in the early retirement of our generation units that do not have SCR and FGD equipment installed. Currently, our coal-fired generation units at Hutchings and Beckjord do not have this emission-control equipment installed. DP&L owns 100% of the Hutchings plant and has a 50% interest in Beckjord Unit 6. In addition to environmental matters, the operation of our coal-fired generation plants could be affected by a multitude of other factors, including forecasted power, capacity and commodity prices, competition and the levels of customer switching, current and forecasted customer demand, cost of capital and regulatory and legislative developments, any of which could pose a potential triggering event for an impairment of our investments in the Hutchings and Beckjord units. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our commonly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. We are depreciating Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision. We are considering options for Hutchings Station, but have not yet made a final decision. We do not believe that any accruals or impairment charges are needed related to the Hutchings Station.
Environmental Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on how much of a pollutant can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.
Cross-State Air Pollution Rule
The Clean Air Interstate Rule (CAIR) final rules were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. Litigation brought by entities not including DP&L resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan. On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Courts July 2008 decision.
In an attempt to conform to the Courts decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). These rules were finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in their implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, it is expected to institute a federal implementation plan (FIP) in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is
unable to estimate the impact of the new requirements; however, CSAPR could have a material effect on our operations.
Mercury and Other Hazardous Air Pollutants
On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The USEPA Administrator signed the final rule, now called MATS (Mercury and Air Toxics Standards), on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Affected electric generating units (EGUs) will have to come into compliance with the new requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our results of operations and result in material compliance costs.
On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers and process heaters at major and area source facilities. The final rule was published in the Federal Register on March 21, 2011. This regulation affects seven auxiliary boilers used for start-up purposes at DP&Ls generation facilities. The regulations contain emissions limitations, operating limitations and other requirements. In December 2011, the USEPA proposed additional changes to this rule and solicited comments. Compliance costs are not expected to be material to DP&Ls operations.
On May 3, 2010, the National Emissions Standards for Hazardous Air Pollutants for compression ignition (CI) reciprocating internal combustion engines (RICE) became effective. The units affected at DP&L are 18 diesel electric generating engines and eight emergency black start engines. The existing CI RICE units must comply by May 3, 2013. The regulations contain emissions limitations, operating limitations and other requirements. Compliance costs for DP&Ls operations are not expected to be material.
National Ambient Air Quality Standards
On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. As of December 31, 2011, DP&Ls Stuart, Killen and Hutchings Stations were located in non-attainment areas for the annual PM 2.5 standard. There is a possibility that these areas will be re-designated as attainment for PM 2.5 within the next few calendar quarters and that the NAAQS for PM 2.5 will become more stringent. We cannot predict the effect the revisions to the PM 2.5 standard will have on DP&Ls financial condition or results of operations.
On September 16, 2009, the USEPA announced that it would reconsider the 2008 national ground level ozone standard. On September 2, 2011, the USEPA decided to postpone their revisiting of this standard until 2013. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.
Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO2 replacing the current 24-hour standard and annual standard with a one hour standard. DP&L cannot determine the effect of this potential change, if any, on its operations.
On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. In the final rule, the USEPA made the determination that CAIR achieves greater progress than BART and may be used by states as a BART substitute and USEPA subsequently determined that if CSAPR becomes effective, it may be used to comply with BART requirements. Numerous units owned and operated by us will be affected by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.
Carbon Emissions and Other Greenhouse Gases
In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, USEPA determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. Numerous affected parties have petitioned the USEPA Administrator to reconsider this decision. On April 1, 2010, USEPA signed the Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards rule. Under USEPAs view, this is the final action that renders carbon dioxide and other GHGs regulated air pollutants under the CAA.
Under USEPA regulations finalized in May 2010 (referred to as the Tailoring Rule), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the Best Available Control Technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.
The USEPA plans to propose GHG standards for new and modified electric generating units (EGUs) under CAA subsection 111(b) and propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d) during 2012. These rules may focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&Ls operations.
Approximately 99% of the energy we produce is generated by coal. DP&Ls share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. Further GHG legislation or regulation finalized at a future date could have a significant effect on DP&Ls operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial effect that such legislation or regulation may have on DP&L.
On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. DP&Ls first report to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other effect on current operations.
Litigation, Notices of Violation and Other Matters Related to Air Quality
Litigation Involving Co-Owned Plants
On June 20, 2011, the U.S.Supreme Court ruled that the USEPAs regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs original suits that sought relief under state law.
As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the J.M. Stuart generating station are subject to certain specified emission targets related to NOx, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&Ls results of operations, financial condition or cash flows in the future.
Notices of Violation Involving Co-Owned Plants
In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and CSP (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. Although DP&L was not identified in the NOVs, civil complaints or state actions, the results of such proceedings could materially affect DP&Ls co-owned plants.
In June 2000, the USEPA issued a NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, Duke Energy and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.
In December 2007, the Ohio EPA issued a NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOV alleged deficiencies in the continuous monitoring of opacity. We submitted a compliance plan to the Ohio EPA on December 19, 2007. To date, no further actions have been taken by the Ohio EPA.
On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received a NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the Station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, USEPA issued an NOV to Zimmer for excess emissions. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.
Notices of Violation Involving Wholly-Owned Plants
In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the O.H. Hutchings Station. The NOVs alleged deficiencies relate to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the O.H. Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the two projects described in the NOV were modifications subject to NSR. DP&L is engaged in discussions with the USEPA and Justice Department to resolve these matters, but DP&L is unable to determine the timing, costs or method by which these issues may be resolved. The Ohio EPA is kept apprised of these discussions.
Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds
Clean Water Act Regulation of Water Intake
On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules. In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available. The USEPA released new proposed regulations on March 28, 2011, which were published in the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. The final rules are expected to be in place by mid-2012. We do not yet know the impact these proposed rules will have on our operations.
Clean Water Act Regulation of Water Discharge
In December 2006, we submitted an application for the renewal of the Stuart Station NPDES Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in a thermal discharge study completed during the previous permit term. Subsequently, DP&L and the Ohio EPA reached an agreement to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. The Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPAs objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit and is considering legal options. Depending on the outcome of the process, the effects could be material on DP&Ls operation.
In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. Subsequent to the information collection effort, it is anticipated that the USEPA will release a proposed rule by mid-2012 with a final regulation in place by early 2014. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.
Regulation of Waste Disposal
In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&Ls service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill sites contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP groups costs associated with the investigation and remediation of the site. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill sites contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, is ongoing. While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.
In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.
On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L. The USEPA has indicated that a proposed rule will be released in late 2012. At present, DP&L is unable to predict the impact this initiative will have on its operations.
Regulation of Ash Ponds
In March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart Stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station.
In August 2010, the USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the O.H. Hutchings Station ash ponds. DP&L is unable to predict whether there will be additional USEPA action relative to DP&Ls proposed plan or the effect on operations that might arise under a different plan.
In June 2011, the USEPA conducted an inspection of the Killen Station ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.
There has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA anticipates issuing a final rule on this topic in late 2012. DP&L is unable to predict the financial effect of this regulation, but if
coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on DP&Ls operations.
Notice of Violation Involving Co-Owned Plants
On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the Clean Water Act National Pollutant Discharge Elimination System permit program and the stations storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPAs findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&Ls results of operations, financial condition or cash flow.
Legal and Other Matters
In February 2007, DP&L filed a lawsuit against a coal supplier seeking damages incurred due to the suppliers failure to supply approximately 1.5 million tons of coal to two commonly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&Ls share. DP&L obtained replacement coal to meet its needs. The supplier 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.
In connection with DP&L and other utilities joining PJM, in 2006, the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&Ls and other utilities position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. With respect to unsettled claims, DP&L management has deferred $17.8 million and $15.4 million as of December 31, 2011 and December 31, 2010, respectively, as Other deferred credits representing the amount of unearned income where the earnings process is not complete. The amount at December 31, 2011 includes estimated earnings and interest of $5.2 million. On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed. These orders are now final, subject to possible appellate court review. These orders do not affect prior settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L. For other parties that had not previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.
Also refer to Notes 2 and 18 of Notes to DPLs Consolidated Financial Statements for additional information surrounding the merger and certain related legal matters.
Capital Expenditures for Environmental Matters
DP&Ls environmental capital expenditures are approximately $12 million, $12 million and $21 million in 2011, 2010 and 2009, respectively. DP&L has budgeted $15 million in environmental related capital expenditures for 2012.
ELECTRIC SALES AND REVENUES
The following table sets forth DPLs electric sales and revenues for the period November 28, 2011 (the Merger date) through December 31, 2011 (Successor), the period January 1, 2011 through November 27, 2011 and the years ended December 31, 2010 and 2009 (Predecessor), respectively.
In the following table, we have included the combined Predecessor and Successor statistical information and results of operations. Such combined presentation is considered to be a non-GAAP disclosure. We have included such disclosure because we believe it facilitates the comparison of 2011 operating and financial performance to 2010 and 2009, and because the core operations of DPL have not changed as a result of the Merger.
DPL is structured in two operating segments, DP&L and DPLER. See Note 19 of Notes to DPLs Consolidated Financial Statements for more information on DPLs segments. The following tables set forth DP&Ls and DPLERs electric sales and revenues for the years ended December 31, 2011, 2010 and 2009, respectively.
(a) DP&L sold 5,731 million kWh, 4,417 million kWh and 1,464 million kWh of power to DPLER (a subsidiary of DPL) for the years ended December 31, 2011, December 31, 2010 and 2009, respectively, which are not included in DP&L wholesale sales volumes in the chart above. These kWh sales also relate to DP&L retail customers within the DP&L service territory for distribution services and their inclusion in wholesale sales would result in a double counting of kWh volume. The dollars of operating revenues associated with these sales are classified as wholesale revenues on DP&Ls Financial Statements and retail revenues on DPLs Consolidated Financial Statements.
(b) This chart includes all sales of DPLER, both within and outside of the DP&L service territory.
Investors should consider carefully the following risk factors that could cause our business, operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. These risk factors should be read in conjunction with the other detailed information concerning DPL set forth in the Notes to DPLs audited Consolidated Financial Statements and DP&L set forth in the Notes to DP&Ls audited Financial Statements in Item 8. Financial Statements and Supplementary Data and in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations herein. The risks and uncertainties described below are not the only ones we face.
Our customers have the opportunity to select alternative electric generation service providers, as permitted by Ohio legislation.
Customers can elect to buy transmission and generation service from a PUCO-certified CRES provider offering services to customers in DP&Ls service territory. DPLER, a wholly-owned subsidiary of DPL, is one of those PUCO-certified CRES providers. Unaffiliated CRES providers also have been certified to provide energy in DP&Ls service territory. Customer switching from DP&L to DPLER reduces DPLs revenues since the generation rates charged by DPLER are less than the SSO rates charged by DP&L. Increased competition by unaffiliated CRES providers in DP&Ls service territory for retail generation service could result in the loss of existing customers and reduced revenues and increased costs to retain or attract customers. Decreased revenues and increased costs due to continued customer switching and customer loss could have a material adverse effect on our results of operations, financial condition and cash flows. The following are some of the factors that could result in increased switching by customers to PUCO-certified CRES providers in the future:
· Low wholesale price levels have led and may continue to lead to existing CRES providers becoming more active in our service territory, and additional CRES providers entering our territory.
· We could experience increased customer switching through governmental aggregation, where a municipality may contract with a CRES provider to provide generation service to the customers located within the municipal boundaries.
We are subject to extensive laws and local, state and federal regulation, as well as related litigation, that could affect our operations and costs.
We are subject to extensive laws and regulation by federal, state and local authorities, such as the PUCO, the CFTC, the USEPA, the Ohio EPA, the FERC, the Department of Labor and the Internal Revenue Service, among others. Regulations affect almost every aspect of our business, including in the areas of the environment, health and safety, cost recovery and rate making, the issuance of securities and incurrence of debt and taxation. New laws and regulations, and new interpretations of existing laws and regulations, are ongoing and we generally cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our business. Complying with this regulatory environment requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business. Additional detail about the effect of this regulatory environment on our operations is included in the risk factors set forth below. In the normal course of business, we are also subject to various lawsuits, actions, proceedings, claims and other matters asserted under this regulatory environment or otherwise, which require us to expend significant funds to address, the outcomes of which are uncertain and the adverse resolutions of which could have a material adverse effect on our results of operations, financial condition and cash flows.
The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedure of the PUCO.
The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO. On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008. This law, among other things, required all Ohio distribution utilities to file either an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that compares the utilitys earnings to the earnings of other companies with similar business and financial risks. The PUCO approved DP&Ls filed ESP on June 24, 2009. DP&Ls ESP provides, among other things, that DP&Ls existing rate plan structure will continue through the end of 2012; that DP&L may seek recovery for adjustments to its existing rate plan structure for costs associated with storm damage, regulatory and tax changes, new climate change or carbon regulations, fuel and purchased power and certain other costs; and that SB 221s significantly excessive earnings test will apply in 2013 based upon DP&Ls 2012 earnings. DP&L faces regulatory uncertainty from its next ESP or MRO filing which is scheduled to be filed on March 30, 2012 to be effective January 1, 2013. The filing may result in changes to the current rate structure and riders that could adversely affect our results of operations, cash flows and financial condition. DP&Ls ESP and certain filings made by us in connection with this plan are further discussed under Ohio Retail Rates in Item 1 COMPETITION AND REGULATION. In addition, as the local distribution utility, DP&L has an obligation to serve customers within its certified territory and under the terms of its ESP Stipulation, as it is the provider of last resort (POLR) for standard offer service. DP&Ls current rate structure provides for a nonbypassable charge to compensate DP&L for this POLR obligation. The PUCO may decrease or discontinue this rate charge at some time in the future.
While rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable or that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and permitted rates of return. Certain of our cost recovery riders are also bypassable by some of our customers who switched to a CRES provider. Accordingly, the revenue DP&L receives may or may not match its expenses at any given time. Therefore, DP&L could be subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of its expenses. Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return and POLR service; changes in DP&Ls rate structure and its ability to recover amounts for environmental compliance, POLR obligations, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and other costs on a full or timely basis through rates; and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.
Our increased costs due to advanced energy and energy efficiency requirements may not be fully recoverable in the future.
SB 221 contains targets relating to advanced energy, renewable energy, peak demand reduction and energy efficiency standards. The standards require that, by the year 2025 and each year thereafter, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include advanced energy resources such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and renewable energy resources such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including solar energy. Annual renewable energy standards began in 2009 with increases in required percentages each year through 2024. The advanced energy standard must be met by 2025 and each year thereafter. Annual targets for energy efficiency began in 2009 and require increasing energy reductions each year compared to a baseline energy usage, up to 22.3% by 2025. Peak demand reduction targets began in 2009 with increases in required percentages each year, up to 7.75% by 2018. The advanced energy and renewable energy standards have increased our power supply costs and are expected to continue to increase (and could materially increase) these costs. Pursuant to DP&Ls approved ESP, DP&L is entitled to recover costs associated with its alternative energy compliance costs, as well as its energy efficiency and demand response programs. DP&L began recovering these costs in 2009. If in the future we are unable to timely or fully recover these costs, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these standards, monetary penalties could apply. These penalties are not permitted to be recovered from customers and significant penalties could have a material adverse effect on our results of operations, financial condition and cash flows. The demand reduction and energy efficiency standards by design result in reduced energy and demand that could adversely affect our results of operations, financial condition and cash flows.
The availability and cost of fuel has experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from fuel availability and price volatility.
We purchase coal, natural gas and other fuel from a number of suppliers. The coal market in particular has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic issues like government-imposed direct costs and permitting issues that affect mining costs and supply availability, the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. Our approach is to hedge the fuel costs for our anticipated electric sales. However, we may not be able to hedge the entire exposure of our operations from fuel price volatility. As of the date of this report, DPL has substantially all of the total expected coal volume needed to meet its retail and firm wholesale sales requirements for 2012 under contract. In 2011, approximately 84% of DP&Ls coal was provided by four suppliers, three of which were under long-term contracts with DP&L. Historically, some of our suppliers and buyers of fuel have not performed on their contracts and have failed to deliver or accept fuel as specified under their contracts. To the extent our suppliers and buyers do not meet their contractual commitments and, as a result of such failure or otherwise, we cannot secure adequate fuel or sell excess fuel in a timely or cost-effective manner or we are not hedged against price volatility, we could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, DP&L is a co-owner of certain generation facilities where it is a non-operating owner. DP&L does not procure or have control over the fuel for these facilities, but is responsible for its proportionate share of the cost of fuel procured at these facilities. Co-owner operated facilities do not always have realized fuel costs that are equal to our co-owners projections, and we are responsible for our proportionate share of any increase in actual fuel costs. Fuel and purchased power costs represent a large and volatile portion of DP&Ls total cost. Pursuant to its ESP for SSO retail customers, DP&L implemented a fuel and purchased power recovery mechanism beginning on January 1, 2010, which subjects our recovery of fuel and purchased power costs to tracking and adjustment on a seasonal quarterly basis. If in the future we are unable to timely or fully recover our fuel and purchased power costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our use of derivative and nonderivative contracts may not fully hedge our generation assets, customer supply activities, or other market positions against changes in commodity prices, and our hedging procedures may not work as planned.
We transact in coal, power and other commodities to hedge our positions in these commodities. These trades are impacted by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. As part of our risk management, we use a variety of non-derivative and derivative instruments, such as swaps, futures and forwards, to manage our market risks. We also use interest rate derivative instruments to hedge against interest rate fluctuations related to our debt. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves managements judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform, which could result in a material adverse effect on our results of operations, financial condition and cash flows.
The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.
In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. The Dodd-Frank Act provides a potential exception from these clearing and cash collateral requirements for commercial end-users. The Dodd-Frank Act requires the CFTC to establish rules to implement the Dodd-Frank Acts requirements and exceptions. Requirements to post collateral could reduce the cost effectiveness of entering into derivative transactions to reduce commodity price and interest rate volatility or could increase the demands on our liquidity or require us to increase our levels of debt to enter into such derivative transactions. Even if we were to qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits or be unable to enter into certain transactions with us. The
occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.
We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations and may expose us to environmental liabilities.
Our operations and facilities (both wholly-owned and co-owned with others) are subject to numerous and extensive federal, state and local environmental laws and regulations relating to various matters, including air quality (such as reductions in NOx, SO2 and particulate emissions), water quality, wastewater discharge, solid waste and hazardous waste. We could also become subject to additional environmental laws and regulations and other requirements in the future (such as reductions in mercury and other hazardous air pollutants, SO3 (sulfur trioxide), regulation of ash generated from coal-based generating stations and reductions in greenhouse gas emissions as discussed in more detail in the next risk factor). With respect to our largest generation station, the J.M. Stuart Station, we are also subject to continuing compliance requirements related to NOx, SO2 and particulate matter emissions under DP&Ls consent decree with the Sierra Club. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and approvals required to operate our business, then our operations could be prevented, delayed or subject to additional costs. Failure to comply with environmental laws, regulations and other requirements may result in the imposition of fines and penalties or other sanctions and the imposition of stricter environmental standards and controls and other injunctive measures affecting operating assets. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. DP&L owns a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, DP&L is responsible for its pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but has limited control over the compliance measures taken by our co-owners. DP&L has an EIR in place as part of its existing rate plan structure, the last increase of which occurred in 2010 and remains at that level through 2012. In addition, DP&Ls ESP permits it to seek recovery for costs associated with new climate change or carbon regulations. While we expect to recover certain environmental costs and expenditures from customers, if in the future we are unable to fully recover our costs in a timely manner or the SSO retail riders are bypassable or additional customer switching occurs, we could have a material adverse effect to our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these environmental laws, regulations or requirements, any penalties that would apply or other resulting costs would likely not be recoverable from customers.
We could be subject to joint and several strict liability for any environmental contamination at our currently or formerly owned, leased or operated properties or third-party waste disposal sites. For example, contamination has been identified at two waste disposal sites for which we are alleged to have potential liability. In addition to potentially significant investigation and remediation costs, any such contamination matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.
Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.
If legislation or regulations at the federal, state or regional levels impose mandatory reductions of greenhouse gases on generation facilities, we could be required to make large additional capital investments and incur substantial costs.
There is an on-going concern nationally and internationally among regulators, investors and others concerning global climate change and the contribution of emissions of GHGs, including most significantly CO2. This concern has led to interest in legislation and action at the international, federal, state and regional levels and litigation, including regulation of GHG emissions by the USEPA. Approximately 99% of the energy we produce is generated by coal. As a result of current or future legislation or regulations at the international, federal, state or regional levels imposing mandatory reductions of CO2 and other GHGs on generation facilities, we could be required to make large additional capital investments and/or incur substantial costs in the form of taxes or emissions allowances. Such legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations. Although DP&L is permitted under its current ESP to seek recovery of costs associated with new climate change or carbon regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows.
Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DP&L sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal price optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread, adjusted for any quality differentials. During 2010 and 2009, DP&L realized net gains from these sales. Sales of coal are affected by a range of factors, including price volatility among the different coal basins and
qualities of coal, variations in power demand and the market price of power compared to the cost to produce power. These factors could cause the amount and price of coal we sell to fluctuate, which could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DP&L may sell its excess emission allowances, including NOx and SO2 emission allowances from time to time. Sales of any excess emission allowances are affected by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory available for sale and changes to the regulatory environment, including the implementation of CSAPR and CAIR. These factors could cause the amount and price of excess emission allowances DP&L sells to fluctuate, which could cause a material adverse effect on DPLs results of operations, financial condition and cash flows for any particular period. Although there has been overall reduced trading activity in the annual NOx and SO2 emission allowance trading markets in recent years, the adoption of regulations that regulate emissions or establish or modify emission allowance trading programs could affect the emission allowance trading markets and have a material effect on DP&Ls emission allowance sales.
The operation and performance of our facilities are subject to various events and risks that could negatively affect our business.
The operation and performance of our generation, transmission and distribution facilities and equipment is subject to various events and risks, such as the potential breakdown or failure of equipment, processes or facilities, fuel supply or transportation disruptions, the loss of cost-effective disposal options for solid waste generated by our facilities (such as coal ash and gypsum), accidents, injuries, labor disputes or work stoppages by employees, operator error, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, performance below expected or required levels, weather-related and other natural disruptions, vandalism, events occurring on the systems of third parties that interconnect to and affect our system and the increased maintenance requirements, costs and risks associated with our aging generation units. Our results of operations, financial condition and cash flows could have a material adverse effect due to the occurrence or continuation of these events.
Diminished availability or performance of our transmission and distribution facilities could result in reduced customer satisfaction and regulatory inquiries and fines, which could have a material adverse effect on our results of operations, financial condition and cash flows. Operation of our owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels and likely result in lost revenues and increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, since over 50% of our base-load generation is derived from co-owned generation stations operated by our co-owners, poor operational performance by our co-owners, misalignment of co-owners interests or lack of control over costs (such as fuel costs) incurred at these stations could have an adverse effect on us. We have constructed and placed into service FGD facilities at most of our base-load generating stations. If there is significant operational failure of the FGD equipment at the generating stations, we may not be able to meet emission requirements at some of our generating stations or, at other stations, it may require us to burn more expensive types of coal or utilize emission allowances. These events could result in a substantial increase in our operating costs. Depending on the degree, nature, extent, or willfulness of any failure to comply with environmental requirements, including those imposed by any consent decrees, such non-compliance could result in the imposition of penalties or the shutting down of the affected generating stations, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Asbestos and other regulated substances are, and may continue to be, present at our facilities. We have been named as a defendant in asbestos litigation, which at this time is not material to us. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.
If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.
As an owner and operator of a bulk power transmission system, DP&L is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. In addition, DP&L is subject to Ohio reliability standards and targets. Compliance with reliability standards subjects us to higher operating costs or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCO will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.
Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.
Weather conditions significantly affect the demand for electric power. In our Ohio service territory, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Unusually mild summers and winters could therefore have an adverse effect on our results of operations, financial condition and cash flows. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs under its ESP, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.
On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM, a regional transmission organization. The price at which we can sell our generation capacity and energy is now dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion and PJMs business rules. While we can continue to make bilateral transactions to sell our generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM. To the extent we sell electricity into the power markets on a contractual basis, we are not guaranteed any rate of return on our capital investments through mandated rates. The results of the PJM RPM base residual auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources and other factors. Auction prices could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows. We cannot predict the outcome of future auctions, but if auction prices are at low levels, our results of operations, financial condition and cash flows could have a material adverse effect.
The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. While PJM transmission rates were initially designed to be revenue neutral, various proposals and proceedings currently taking place at FERC may cause transmission rates to change from time to time. In addition, PJM has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial effect on us. We also incur fees and costs to participate in PJM.
SB 221 includes a provision that allows electric utilities to seek and obtain recovery of RTO related charges. Therefore, most if not all of the above costs are currently being recovered through our SSO retail rates. If in the future, however, we are unable to recover all of these costs in a timely manner, or the SSO retail riders are bypassable or additional customer switching occurs, our results of operations, financial condition and cash flows could have a material adverse effect.
As members of PJM, DP&L and DPLE are also subject to certain additional risks including those associated with the allocation among PJM members of losses caused by unreimbursed defaults of other participants in PJM markets and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L and DPLE. These amounts could be significant and have a material adverse effect on our results of operations, financial condition and cash flows.
Costs associated with new transmission projects could have a material adverse effect on our results of operations, financial condition and cash flows.
Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. FERC orders issued in 2007 and thereafter modified the traditional method of allocating costs associated with new high-voltage planned transmission facilities. FERC ordered that the cost of new high-voltage facilities be socialized across the PJM region. Various parties, including DP&L, challenged this allocation method and in 2009, the U.S. Court of Appeals, Seventh Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method and remanded the case to the FERC for further proceedings. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. The overall impact of FERCs allocation methodology cannot be definitively assessed because not all new planned construction is likely to happen. To date, the additional costs charged to DP&L for new large transmission approved projects has not been material. Over time, as more new transmission projects are constructed and if the allocation method is not changed, the annual costs could become material. Although we continue to maintain that the costs of these projects should be borne by the direct beneficiaries of the projects and that DP&L is not one of these beneficiaries, DP&L is recovering the Ohio retail jurisdictional share of these allocated costs from its SSO retail customers through the TCRR rider. To the extent that any costs in the future are material and we are unable to recover them from our customers, it could have a material adverse effect on our results of operation, financial condition and cash flows.
Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows.
From time to time we rely on access to the credit and capital markets to fund certain of our operational and capital costs. These capital and credit markets have experienced extreme volatility and disruption and the ability of corporations to obtain funds through the issuance of debt or equity has been negatively impacted. Disruptions in the credit and capital markets make it harder and more expensive to obtain funding for our business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability. DP&L has variable rate debt that bears interest based on a prevailing rate that is reset weekly based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also currently maintain both cash on deposit and investments in cash equivalents that could be adversely affected by interest rate fluctuations. In addition, ratings agencies issue credit ratings on us and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. As a result of the Merger and assumption by DPL of merger-related debt, our credit ratings were reduced, resulting in increased borrowing costs and causing us to post cash collateral with certain of our counterparties. If the rating agencies were to reduce our credit ratings further, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
Poor investment performance of our benefit plan assets and other factors impacting benefit plan costs could unfavorably affect our liquidity and results of operations.
The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. The Pension Protection Act, enacted in August 2006, requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans at times have increased and may increase in the future. In addition, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postretirement benefit
plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.
Our businesses depend on counterparties performing in accordance with their agreements. If they fail to perform, we could incur substantial expense, which could adversely affect our liquidity, cash flows and results of operations.
We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components (such as limestone for our FGD equipment), for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. These events could cause our results of operations, financial condition and cash flows to be materially adversely effected.
Our consolidated results of operations may be negatively affected by overall market, economic and other conditions that are beyond our control.
Economic pressures, as well as changing market conditions and other factors related to physical energy and financial trading activities, which include price, credit, liquidity, volatility, capacity, transmission and interest rates, can have a significant effect on our operations and the operations of our retail, industrial and commercial customers and our suppliers. The direction and relative strength of the economy has been increasingly uncertain due to softness in the real estate and mortgage markets, volatility in fuel and other energy costs, difficulties in the financial services sector and credit markets, high unemployment and other factors. Many of these factors have affected our Ohio service territory.
Our results of operations, financial condition and cash flows may be negatively affected by sustained downturns or a sluggish economy. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. During economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. In addition, our customers ability to pay us could also be impaired, which could result in an increase in receivables and write-offs of uncollectible accounts. Our suppliers could also be affected by the economic downturn resulting in supply delays or unavailability. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows.
Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing.
Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP in the United States of America, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
New accounting standards or changes to existing accounting standards could materially affect how we report our results of operations, financial condition and cash flows.
Our Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could
materially affect how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our Consolidated Financial Statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.
The SEC is investigating the potential transition to the use of International Financial Reporting Standards (IFRS) promulgated by the International Accounting Standards Board for U.S. companies. Adoption of IFRS could result in significant changes to our accounting and reporting, such as in the treatment of regulatory assets and liabilities and property. The SEC expects to make a determination in 2012 regarding the mandatory adoption of IFRS. We are currently assessing the effect that this potential change would have on our Consolidated Financial Statements and we will continue to monitor the development of the potential implementation of IFRS.
If we are unable to maintain a qualified and properly motivated workforce, our results of operations, financial condition and cash flows could have a material adverse effect.
One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations, financial condition and cash flows could have a material adverse effect. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate excessive risk-taking by employees; since excessive risk-taking by our employees to achieve performance targets could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements and other employee workforce factors that could affect our businesses.
Over half of our employees are represented by a collective bargaining agreement that is in effect until October 31, 2014. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the bargaining agreement or at the expiration of the collective bargaining agreement before a new agreement is negotiated. Work stoppages by, or poor relations or ineffective negotiations with, our employees could have a material adverse effect on our results of operations, financial condition and cash flows.
Potential security breaches (including cybersecurity breaches) and terrorism risks could adversely affect our business.
We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation plants, fuel storage facilities, transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war. We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely way to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenues and increases in costs that could adversely affect our results of operations, cash flows and financial condition.
In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information. If our or our third party vendors systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.
To help mitigate against these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.
DPL is a holding company and parent of DP&L and other subsidiaries. DPLs cash flow is dependent on the operating cash flows of DP&L and its other subsidiaries and their ability to pay cash to DPL.
DPL is a holding company and its investments in its subsidiaries are its primary assets. A significant portion of DPLs business is conducted by its DP&L subsidiary. As such, DPLs cash flow is dependent on the operating cash flows of DP&L and its ability to pay cash to DPL. DP&Ls governing documents contain certain limitations on the ability to declare and pay dividends to DPL while preferred stock is outstanding. Certain of DP&Ls debt agreements also contain limits with respect to the ability of DP&L to incur debt. In addition, DP&L is regulated by the PUCO, which possesses broad oversight powers to ensure that the needs of utility customers are being met. While we are not currently aware of any plans to do so, the PUCO could attempt to impose restrictions on the ability of DP&L to distribute, loan or advance cash to DPL pursuant to these broad powers. As part of the PUCOs 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. While we do not expect any of the foregoing restrictions to significantly affect DP&Ls ability to pay funds to DPL in the future, a significant limitation on DP&Ls ability to pay dividends or loan or advance funds to DPL would have a material adverse effect on DPLs results of operations, financial condition and cash flows.
We will be subject to business uncertainties during the integration process with respect to the Merger with The AES Corporation that could adversely affect our financial results.
Uncertainty about the effect of the Merger on DPL and DP&L, their employees, customers and suppliers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties could cause customers, suppliers and others that deal with us to seek to change existing business relationships.
The success of our business will depend on DPLs and DP&Ls ability to realize anticipated benefits from the integration into AES. Certain risks to achieving these benefits include:
· the ability to successfully integrate into AES;
· on-going operating performance;
· the adaptability to changes resulting from the Merger; and
· continued employee retention and recruitment after the Merger.
We expect that matters relating to the Merger and integration-related issues will place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Merger integration-related issues could affect our financial results.
Lawsuits have been filed and several other lawsuits may be filed against DPL, its former directors, AES and Dolphin Sub, Inc. challenging the Merger Agreement, and an adverse judgment in such lawsuits may cause us to pay damages.
DPL and its directors have been named and AES and Dolphin Sub, Inc. have also been named, as defendants in purported class action and derivative action lawsuits filed by certain of our shareholders challenging the Merger and seeking, among other things, to rescind the Merger and to recover an unspecified amount of damages and costs. We could also be subject to additional litigation related to the Merger. While we currently believe that any such litigation is without merit, defending such matters could be costly and distracting to management and an adverse judgment in such lawsuits could affect the Merger or cause us to pay damages and costs.
Push-down accounting adjustments in connection with the Merger may have a material effect on DPLs future financial results.
Under U.S. GAAP, pursuant to FASC No. 805 and SEC Staff Accounting Bulletin Topic 5.J. New Basis of Accounting Required in Certain Circumstances, when an acquisition results in an entity becoming substantially wholly-owned, push-down accounting is applied in the acquired entitys separate financial statements. Push-down accounting requires that the fair value adjustments and goodwill or negative goodwill identified by the acquiring entity be pushed down and reflected in the financial statements of the acquired entity. As a result, following the completion by AES of its purchase price allocation in connection with the merger, the cost basis of certain of DPLs assets and liabilities has been and will continue to be adjusted and any resulting goodwill will be allocated and pushed down to DPL. AES is still in the preliminary stages of determining the adjustments, which are based on preliminary purchase price allocations and preliminary valuations of DPLs assets and liabilities (and will be subject to change within the applicable measurement period). These adjustments could have a material effect on
DPLs future financial condition and results of operations, including but not limited to increased depreciation, amortization, impairment and other non-cash charges. As a result, DPLs actual future results may not be comparable with results in prior periods.
Impairment of goodwill or long-lived assets would negatively affect our consolidated results of operations and net worth.
Goodwill represents the future economic benefits arising from assets acquired in a business combination (acquisition) that are not individually identified and separately recognized. 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 managements 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 along such costs 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. As a result of the pushdown of purchase accounting to DPL from the acquisition of DPL by AES in November 2011, we had $2.5 billion of goodwill at December 31, 2011, which represented approximately 41% of total assets.
Long-lived assets are initially recorded at fair value when acquired in a business combination and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.
Information relating to our properties is contained in Item 1 ELECTRIC OPERATIONS AND FUEL SUPPLY and Note 5 of Notes to DPLs Consolidated Financial Statements and Note 5 of Notes to DP&Ls Financial Statements.
Substantially all property and plants of DP&L are subject to the lien of the mortgage securing DP&Ls First and Refunding Mortgage, dated as of October 1, 1935, as amended with the Bank of New York Mellon, as Trustee (Mortgage).
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below) and to comply with applicable laws and regulations will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2011, cannot be reasonably determined.
The following additional information is incorporated by reference into this Item: (i) information about the legal proceedings contained in Item 1 COMPETITION AND REGULATION of Part 1 of this Annual Report on Form 10-K and (ii) information about the legal proceedings contained in Item 8 Note 18 of Notes to the DPLs Consolidated Financial Statements of Part II of this Annual Report on Form 10-K.
All of the outstanding common stock of DPL is owned indirectly by AES and directly by an AES wholly-owned subsidiary, and as a result is not listed for trading on any stock exchange. DP&Ls common stock is held solely by DPL and, as a result, is not listed for trading on any stock exchange.
During the period November 28, 2011 through December 31, 2011 (Successor), DPL paid dividends of $0.54 per share of DPL common stock that were declared during November 2011. In addition, during the period January 1, 2011 through November 27, 2011 (Predecessor), DPL declared dividends of $1.54 per share of common stock. During the years ended December 31, 2010 and 2009, DPL declared and paid dividends per share of common stock of $1.21 and $1.14, respectively. DP&L declares and pays dividends to its parent DPL from time to time as declared by the DPL board. Dividends in the amount of $220.0 million, $300.0 million and $325.0 million were paid in the years ended December 31, 2011, 2010 and 2009, respectively.
DPLs Amended Articles of Incorporation contain provisions restricting the payment of distributions to its shareholder and the making of loans to its affiliates (other than its subsidiaries). DPL may not make a distribution to its shareholder if, after giving effect to the distribution, DPL would be unable to pay its debts as they become due or DPLs total assets would be less than its total liabilities. In addition, DPL may not make a distribution to its shareholder or a loan to any of its affiliates (other than its subsidiaries), unless generally: (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 (b) at the time and as a result of the distribution or loan, DPLs leverage and interest coverage ratios are within certain parameters as set forth in the Articles and is noted below or, if such ratios are not within the parameters, DPLs senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. The restrictions in the immediately preceding sentence will cease to be in effect if the three major credit rating agencies confirm that a lowering of DPLs senior long-term debt rating below investment grade by the credit rating agencies would not occur without the restrictions.
The parameters under DPLs Amended Articles of Incorporation for the leverage and interest ratios noted above are:, DPLs leverage ratio is not to exceed 0.67:1.00 and DPLs interest coverage ratio is not to be less than 2.5:1.0. At December 31, 2011, the leverage ratio was 0.55:1.00 and the interest coverage ratio was 7.5:1.0.
As long as DP&L preferred stock is outstanding, DP&Ls Amended Articles of Incorporation 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&Ls ability to pay cash dividends and, as of December 31, 2011, DP&Ls retained earnings of $589.1 million were all available for DP&L common stock dividends payable to DPL.
DPL did not repurchase any of its common stock during the twelve months ended December 31, 2011.
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. Managements Discussion and Analysis of Financial Condition and Results of Operations. The Results of Operations discussion in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations addresses significant fluctuations in operating data. DPL is a wholly-owned, indirect subsidiary of AES and therefore does not report earnings or dividends on a per-share basis. Other data that management believes is important in understanding trends in our business are also included in this table.