DPL 10-K 2011
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
For the transition period from to
Each of the following classes or series of securities registered pursuant to Section 12 (b) of the Act is registered on the New York Stock Exchange:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
The aggregate market value of DPL Inc.s common stock held by non-affiliates of DPL Inc. as of June 30, 2010 was approximately $2.8 billion based on a closing sale price of $23.90 on that date as reported on the New York Stock Exchange. All of the common stock of The Dayton Power and Light Company is owned by DPL Inc. As of February 15, 2011, each registrant had the following shares of common stock outstanding:
This combined Form 10-K is separately filed by DPL Inc. and The Dayton Power and Light Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of DPLs definitive proxy statement for its 2011 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K.
DPL Inc. and The Dayton Power and Light Company
Fiscal Year Ended December 31, 2010
The following select abbreviations or acronyms are used in this Form 10-K:
This report includes the combined filing of DPL and DP&L. DP&L is the principal subsidiary of DPL providing approximately 93% of DPLs total consolidated gross margin and approximately 91% of DPLs total consolidated asset base. 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.
WEBSITE ACCESS TO REPORTS
We file current, annual and quarterly reports and other information required by the Securities Exchange Act of 1934, as amended, with the SEC. You may read and copy any document we file at the SECs public reference room located at 100 F Street N.E., Washington, D.C. 20549, USA. Please call the SEC at (800) SEC-0330 for further information on the public reference rooms. Our SEC filings are also available to the public from the SECs website at http://www.sec.gov.
Our public internet site is http://www.dplinc.com. We make available, free of charge, through our internet site, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and Forms 3, 4 and 5 filed on behalf of our directors and executive officers and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
In addition, our public internet site includes other items related to corporate governance matters, including, among other things, our governance guidelines, charters of various committees of the Board of Directors and our code of business conduct and ethics applicable to all employees, officers and directors. You may obtain copies of these documents, free of charge, by sending a request, in writing, to DPL Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.
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. Please see page 37 for more information about forward-looking statements contained in 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.
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.
During 2010, DPL, for the first time, met the GAAP requirements for separate segment reporting. DPLs two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 17 of Notes to Consolidated Financial Statements for more information relating to these reportable segments. DP&L does not have any reportable segments.
DPLER sells competitive retail electric service, under contract, primarily to commercial and industrial customers. DPLER has approximately 9,000 customers currently located throughout Ohio. All of DPLERs electric energy was purchased from DP&L to meet these sales obligations. During 2010, we implemented a new wholesale agreement between DP&L and DPLER. Under this agreement, intercompany sales from DP&L to DPLER were based on the market prices for wholesale power. In 2009 and prior periods, DPLERs purchases from DP&L were transacted at prices that approximated DPLERs sales prices to its end-use retail customers. The operations of DPLER are not subject to rate regulation by federal or state regulators.
DPLs other significant subsidiaries (all of which are wholly-owned) include: DPLE, which engages in the operation of peaking generating facilities and sells power in wholesale markets and MVIC, which is our captive insurance company that provides insurance to us and our subsidiaries.
DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.
DP&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 employed 1,494 persons as of January 31, 2011, of which 1,321 were full-time employees and 173 were part-time employees. At that date, 1,298 of these full-time employees and substantially all of the part-time employees were employed by DP&L. Approximately 54% of the employees are under a collective bargaining agreement.
On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. The facility contains one financial covenant: DP&Ls total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This facility also contains a $50 million letter of credit sublimit.
On December 1, 2010, DP&L renewed two $50 million LOC agreements with JPMorgan Chase Bank, N.A. These agreements are for three years, expiring December 9, 2013. The irrevocable LOCs continue to back the payment of principal and interest relating to the $100 million State of Ohio Collateralized Air Quality Development Revenue Refunding Bonds, 2008 Series A and B which are due in November 2040.
Stock Repurchase Plan
On October 27, 2010, the DPL Board of Directors approved a new stock repurchase plan to acquire up to $200 million of DPL common stock. Under this plan, DPL may repurchase its common stock from time to time in the open market, through private transactions or otherwise, on such terms and conditions as the company deems appropriate. The company expects to subject the purchases to restrictions relating to volume, price and timing in an effort to minimize the impact of the purchases upon the market for its common stock. DPL intends to fund purchases from cash on hand, available borrowings, cash flow from operations and proceeds from potential debt or other capital market transactions. The plan will run through December 31, 2013, but may be modified or terminated at any time without prior notice. Through December 31, 2010, DPL repurchased approximately 2.04 million shares of common stock under this stock repurchase plan at an average price per share of $25.75.
Construction of Yankee Solar Facility
On April 23, 2010, DP&Ls Yankee solar station, a certified Ohio Renewable Energy Resource Generating Facility, was placed into service. The Yankee facility is comprised of 9,120 solar panels constructed over approximately 7 acres of land located in the Dayton, Ohio area. The facility is expected to generate approximately 1,390 MWh of electric energy per year which is sufficient to power the equivalent of approximately 150 homes a year.
During 2010, there were 4 additional unaffiliated marketers that registered as CRES providers in DP&Ls service territory. We have experienced increased competition to provide transmission and generation services to our retail customers. DPLER, a CRES provider that is also a subsidiary of DPL, accounted for approximately 97% of the total retail energy supplied by CRES providers within DP&Ls service territory in 2010. During 2010, 847 customers with an energy usage of 145 million kWh were supplied by other CRES providers within DP&Ls service territory, compared to 44 customers that had an energy usage of 16 million kWh during 2009. For the year ended December 31, 2010, the reduction in DPLs and DP&Ls gross margin as a result of customers switching to DPLER and other CRES providers is estimated to be approximately $17 million and $53 million, respectively.
Increase in Dividends on DPLs Common Stock
On December 8, 2010, DPLs Board of Directors authorized a quarterly dividend rate increase of approximately 10%, increasing the quarterly dividend per DPL common share from $.3025 to $.3325. If this dividend rate is maintained, the annualized dividend would increase from $1.21 per share to $1.33 per share.
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 3,261 MW. Of this capacity, approximately 2,830 MW, or 87%, is derived from coal-fired steam generating stations and the balance of approximately 431 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, 884 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 2010, we generated 98.9% of our electric output from coal-fired units and 1.1% 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.
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 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 2011 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 jointly 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 2011.
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 3 of Notes to Consolidated 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. 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 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. The PUCO issued three sets of rules related to implementation of the law. These rules address topics such as the information that must be included in an ESP as well as a MRO, the significantly excessive earnings test requirements, corporate separation revisions, rules relating to the recovery of transmission related costs, electric service and safety standards dealing with the statewide line extension policy, and rules relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.
In compliance with SB 221, DP&L filed its ESP at the PUCO on October 10, 2008. This plan contained three parts: 1) a standard offer plan; 2) a CCEM plan; and 3) an alternative energy plan. After discussions with Commission Staff, the Ohio Consumers Counsel and other interested parties, an ESP Stipulation was agreed to and filed on February 24, 2009. The ESP Stipulation, among other things, extended the Companys rate plan through 2012, provided for recovery of the Ohio retail customers portion of fuel and purchased power costs beginning January 2010, provided for recovery of certain SB 221 compliance costs, and required DP&L to re-file its Smart Grid and advanced metering infrastructure (AMI) business cases, which were part of the CCEM plan, by September 1, 2009. On June 24, 2009, the PUCO issued an order granting approval of the ESP Stipulation as filed and authorized DP&L to implement rates associated with alternative energy and energy efficiency compliance costs, which DP&L implemented beginning on July 1, 2009.
Consistent with the ESP Stipulation, DP&L re-filed its Smart Grid and AMI business cases with the PUCO on August 4, 2009 seeking recovery of costs associated with a three-year plan to deploy AMI; and a ten-year plan for distribution and substation automation, core telecommunications, supporting software and in-home technologies. In August 2009, DP&L submitted an application for American Recovery and Reinvestment Act (ARRA) funding for the Smart Grid Investment Grant Program, seeking $145.1 million of matching funds but was notified in October 2009, that we would not receive funding under the ARRA. On October 19, 2010, DP&L elected to withdraw the re-filed case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future.
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. In December 2009, DP&L made several filings relating to its renewable energy and energy efficiency compliance plans. DP&L was able to obtain Renewable Energy Credits sufficient to meet its non-solar renewable energy targets, but obtained only 36% of the 2009 Ohio-based solar resources. DP&L requested a waiver of any unmet 2009 Ohio solar requirements on grounds of force majeure because there were insufficient solar renewable energy credits available from Ohio resources. In March 2010, the PUCO ruled that DP&Ls 2009 Ohio solar target would be reduced to the amount that it had procured, but that any unmet requirement must be added to the 2010 target. DP&L has been able to acquire sufficient renewable resources in 2010 to meet its 2010 requirements plus that portion of the 2009 Ohio solar requirement that was added by the PUCO order.
On April 15, 2010, DP&L made its first annual required filing related to compliance with renewable and advanced energy targets contained in SB 221. Pursuant to PUCO rules, each April 15, DP&L and DPLER who are electric services companies pursuant to Ohio Revised Code, are required to provide a status report on whether or not they met the renewable benchmarks of the previous year, as well as a ten-year plan outlining their plans to meet future annual renewable targets. In addition, on April 15 of each year, each utility that owns an electric generating facility in Ohio must report to the PUCO regarding its greenhouse gas emissions, and plans to reduce those emissions (environmental control plan) as well as a long-term forecast report which includes a plan to provide sufficient resources to meet customer load obligations (resource plan). DP&Ls long-term forecast filing was set for hearing. A settlement was reached in early 2011 under which the need for solar facilities was established. This settlement was filed with the PUCO for their approval.
In two separate filings, DP&L requested the PUCOs consent that DP&L had met the 2009 requirements for energy efficiency and for demand reduction based on DP&Ls interpretation of how those requirements should be applied. These filings also requested that if the PUCO disagreed with DP&Ls interpretation, the PUCO grant alternative relief and find that DP&L was unable to meet the targets due to reasons beyond its reasonable control, i.e., uncertainty throughout 2009 caused by delays in finalizing the rules and the lack of timely PUCO action on several of DP&Ls special contracts relating to demand response efforts which remain pending before the PUCO. Since this is a new process, it is unclear if a final order will be issued in these proceedings.
In addition, the rules that became effective December 10, 2009 required that on January 1, 2010, DP&L file an extensive energy efficiency portfolio plan, outlining how DP&L plans to comply with the energy efficiency and demand reduction benchmarks. DP&L filed a separate request for a finding that it had already complied with this requirement in the form of DP&Ls portfolio plan that had been filed in 2008 as part of its CCEM plan, which had been approved by the PUCO and is being implemented. On May 19, 2010 the Commission approved in part and denied in part DP&Ls request that the Commission 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 within 60 days of the date of the order. We made this filing on July 15, 2010. Although this case was set for hearing settlement talks are on-going.
We are unable to predict how the PUCO will respond to many of the filings discussed above, but believe that the outcome will not be material to our financial condition. 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 could have a material impact on our financial condition.
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. DP&L is currently undergoing an audit of its fuel rider which is conducted by an independent third party in accordance with the PUCO standards. As a result there is some uncertainty as to the costs that will be approved for recovery. DP&L anticipates that some of this uncertainty will be resolved during the summer of 2011 after completion of the fuel audit. Based on the results of the audit, DP&L may record a favorable or unfavorable adjustment to earnings. It is too early to determine if any such adjustment would be material to our results of operations, financial condition and cash flows.
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 28, 2010. On October 15, 2010 DP&L made an interim adjustment to both the TCRR and the RPM riders that had no material change to the rate recovery amounts.
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 2010 based on 2009 results. 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 impact 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). The PUCO issued a procedural schedule and held a technical conference in November 2009. Comments and reply comments were filed. 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, DP&L will be subject to financial penalties if the established targets are not met for two consecutive years.
While the overall financial impact of SB 221 will not be known for some time, implementation of the bill and compliance with its requirements could have a material impact on our financial condition.
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.
Overall power market prices, as well as government aggregation initiatives within DP&Ls service territory, have led or may lead to the entrance of additional competitors in our service territory. During the year ended December 31, 2010, there were four additional unaffiliated marketers that registered as CRES providers in DP&Ls service territory, bringing the total number of CRES providers in DP&Ls service territory to eleven. DPLER, an affiliated company and one of the eleven registered CRES providers, has been marketing transmission and generation services to DP&L customers. During 2010, DPLER accounted for approximately 4,417 million kWh of the total 4,562 million kWh supplied by CRES providers within DP&Ls service territory. Also during 2010, 847 customers with an annual energy usage of 145 million kWh were supplied by other CRES providers within DP&Ls service territory, compared to 44 customers that had an annual energy usage of 16 million kWh during 2009. The volume supplied by DPLER represents approximately 31% of DP&Ls total distribution sales volume during 2010. The reduction to gross margin in 2010 as a result of customers switching to DPLER and other CRES providers was approximately $17 million and $53 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 impact 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, none of these communities have aggregated their generation load.
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 impact on our results of operations, financial condition or cash flows.
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 price, 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 1,000 miles of high-voltage transmission 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 51 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 2013/2014 period cleared at a per megawatt price of $28/day for our RTO area. The per megawatt prices for the periods 2012/2013, 2011/2012 and 2010/2011 were $16/day, $110/day and $174/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 sustained, our future results of operations, financial condition and cash flows could have a material adverse impact.
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, 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 appeals 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 in late February. 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 wherein 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 environmental regulations and laws by federal, state and local authorities. The environmental issues that may impact 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 and NOx emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions.
· Rules issued by the USEPA and Ohio EPA that require reporting and future rules that may require reductions of GHGs.
· Rules and future rules issued by the USEPA associated with the Federal Clean Water Act (FCWA), 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 by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the EPA is reconsidering that determination. A change in determination could significantly increase the costs of disposing of such by-products.
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 $4.0 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 effect on our results of operations, financial condition or cash flows.
In July 2010, the USEPA proposed new rules to limit the interstate transport of emissions of NOx and SO2 that would, if finalized, have a significant industry-wide impact on the operation of coal-fired generation units. We also have several other pending environmental matters associated with our coal-fired generation units and these pending matters, along with the new rules proposed by the USEPA, 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 and their early retirement could occur as early as 2015. 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 impacted 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.
Regulation Matters Related to Air Quality
Clean Air Act Compliance
In 1990, the federal government amended the CAA to further regulate air pollution. Under the law, the USEPA sets limits on how much of a pollutant can be in the air anywhere in the United States. The CAA allows individual states to have stronger pollution controls, 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.
On October 27, 2003, the USEPA published final rules regarding the equipment replacement provision (ERP) of the routine maintenance, repair and replacement (RMRR) exclusion of the CAA. Activities at power plants that fall within the scope of the RMRR exclusion do not trigger new source review (NSR) requirements, including the imposition of stricter emission limits. On December 24, 2003, the United States Court of Appeals for the D.C. Circuit stayed the effective date of the rule pending its decision on the merits of the lawsuits filed by numerous states and environmental organizations challenging the final rules. On June 6, 2005, the USEPA issued its final response on the reconsideration of the ERP exclusion. The USEPA clarified its position, but did not change any aspect of the 2003 final rules. This decision was appealed and the D.C. Circuit vacated the final rules on March 17, 2006. The scope of the RMRR exclusion remains uncertain due to this action by the D.C. Circuit, as well as multiple litigations not directly involving us where courts are defining the scope of the exception with respect to the specific facts and circumstances of the particular power plants and activities before the courts. While we believe that we have not engaged in any activities with respect to our existing power plants that would trigger the NSR requirements, if NSR requirements were imposed on any of DP&Ls existing power plants, the results could have a material adverse impact to us.
The USEPA issued a proposed rule on October 20, 2005 concerning the test for measuring whether modifications to electric generating units should trigger application of NSR standards under the CAA. A supplemental rule was also proposed on May 8, 2007 to include additional options for determining if there is an emissions increase when an existing electric generating unit makes a physical or operational change. The rule was challenged by environmental organizations and has not been finalized. While we cannot predict the outcome of this rulemaking, any finalized rules could materially affect our operations.
Interstate Air Quality Rule
On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap SO2 and NOx emissions from electric utilities. The proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and ozone pollution in other downwind states in the eastern United States. On June 10, 2004, the USEPA issued a supplemental proposal to the IAQR, now renamed the Clean Air Interstate Rule (CAIR). The final rules were signed on March 10, 2005 and 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. On August 24, 2005, the USEPA proposed additional revisions to the CAIR. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision to vacate the USEPAs CAIR and its associated Federal Implementation Plan and remanded to the USEPA with instructions to issue new regulations that conformed with the procedural and substantive requirements of the CAA. The Courts decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 emission trading program established by the March 10, 2005 rules, and created uncertainty regarding future NOx and SO2 emission reduction requirements and their timing. The USEPA and a group representing utilities filed a request on September 24, 2008 for a rehearing before the entire Court. 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 11, 2008 decision.
On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) which may replace CAIR in 2012. We have reviewed this proposal and submitted comments to the USEPA on September 30, 2010. We are unable to determine the overall financial impact that these rules could have on our operations in the future.
In 2007, the Ohio EPA revised their State Implementation Plan (SIP) to incorporate a CAIR program consistent with the IAQR. The Ohio EPA had received partial approval from the USEPA and had been awaiting full program approval from the USEPA when the U.S. Court of Appeals issued its July 11, 2008 decision. As a result of the December 23, 2008 order, the Ohio EPA proposed revised rules on May 11, 2009, which were finalized on July 15, 2009. On September 25, 2009, the USEPA issued a full SIP approval for the Ohio CAIR program. We do not expect that full SIP approval of the Ohio CAIR program will have a significant impact on operations.
Mercury and Other Hazardous Air Pollutants
On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The USEPA de-listed mercury as a hazardous air pollutant from coal-fired and oil-fired utility plants and, instead, proposed a cap-and-trade approach to regulate the total amount of mercury emissions allowed from such sources. The final Clean Air Mercury Rule (CAMR) was signed March 15, 2005 and was published on May 18, 2005. On March 29, 2005, nine states sued the USEPA, opposing the cap-and-trade regulatory approach taken by the USEPA. In 2007, the Ohio EPA adopted rules implementing the CAMR program. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit struck down the USEPA regulations, finding that the USEPA had not complied with statutory requirements applicable to de-listing a hazardous air pollutant and that a cap-and-trade approach was not authorized by law for listed hazardous air pollutants. A request for rehearing before the entire Court of Appeals was denied and a petition for review before the U.S. Supreme Court was filed on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the petition. The USEPA is expected to propose Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units during the quarter ending March 31, 2011 and finalize them during the quarter ending December 31, 2011. Upon publication in the federal register following finalization, affected electric generating units (EGUs) will have three years to come into compliance with the new requirements. DP&L is unable to determine the impact of the promulgation of new MACT standards on its financial condition or results of operations; however, a MACT standard could have a material adverse effect on our operations. We cannot predict the final costs we may incur to comply with proposed new regulations to control mercury or other hazardous air pollutants.
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. This regulation may affect five auxiliary boilers used for start-up purposes at DP&Ls generation facilities. The proposed regulations contain emissions limitations, operating limitations and other requirements. The compliance schedule will be three years from the date when these rules, if finalized, become effective. We currently cannot determine whether or not these rules will be finalized nor can we predict the effect of compliance costs, if any, on DP&Ls operations. Such costs, however, are not expected to be material.
On May 3, 2010, the USEPA finalized the National Emissions Standards for Hazardous Air Pollutants (NESHAP) for compression ignition (CI) reciprocating internal combustion engines (RICE). 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 on 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. On March 4, 2005, DP&L and other Ohio electric utilities and electric generators filed a petition for review in the D.C. Circuit Court of Appeals, challenging the final rule creating these designations. On November 30, 2005, the court ordered the USEPA to decide on all petitions for reconsideration by January 20, 2006. On January 20, 2006, the USEPA denied the petitions for reconsideration. On July 7, 2009, the D.C. Circuit Court of Appeals upheld the USEPA non-attainment designations for the areas impacting DP&Ls generation plants, however, on October 8, 2009 the USEPA issued new designations based on 2008 monitoring data that showed all areas in attainment to the standard with the exception of several counties in northeastern Ohio. The USEPA is expected to propose revisions to the PM 2.5 standard during the first quarter of 2011 as part of its routine five-year rule review cycle. We cannot predict the impact the revisions to the PM 2.5 standard will have on DP&Ls financial condition or results of 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. Numerous units owned and operated by us will be impacted by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.
On September 16, 2009, the USEPA announced that it would reconsider the 2008 national ground level ozone standard. A more stringent ambient ozone standard may lead to stricter NOx emission standards in the future. 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.
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. As a result of this action, it is expected that in 2011 various permitting programs will apply to other combustion sources, such as coal-fired power plants. We cannot predict the effect of this change, if any, on DP&Ls operations.
Legislation proposed in 2009 to target a reduction in the emission of GHGs from large sources was not enacted. 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. Proposed GHG legislation 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, we cannot predict the final outcome or the financial impact that this legislation will 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. The first report is due in March 2011 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 impact on current operations.
Litigation, Notices of Violation and Other Matters Related to Air Quality
Litigation Involving Co-Owned Plants
In 2004, eight states and the City of New York filed a lawsuit in Federal District Court for the Southern District of New York against American Electric Power Company, Inc. (AEP), one of AEPs subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. A similar lawsuit was filed against these companies in the same court by Open Space Institute, Inc., Open Space Conservancy, Inc. and The Audubon Society of New Hampshire. The lawsuits allege that the companies emissions of CO2 contribute to global warming and constitute a public or private nuisance. The lawsuits seek injunctive relief in the form of specific emission reduction commitments. In 2005, the Federal District Court dismissed the lawsuits, holding that the lawsuits raised political questions that should not be decided by the courts. The plaintiffs appealed. Finding that the plaintiffs have standing to sue and can assert federal common law nuisance claims, the United States Court of Appeals for the Second Circuit on September 21, 2009 vacated the dismissal of the Federal District Court and remanded the lawsuits back to the Federal District Court for further proceedings. In response to a petition by the company defendants, the U.S. Supreme Court on December 6, 2010 granted a hearing on the matter. 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 be affected by the outcome of these lawsuits. The outcomes of these lawsuits could also encourage these or other plaintiffs to file similar lawsuits against other electric power companies, including DP&L. We are unable to predict the impact that these lawsuits might have on DP&L.
On September 21, 2004, the Sierra Club filed a lawsuit against DP&L and the other owners of the J.M. Stuart generating station in the U.S. District Court for the Southern District of Ohio for alleged violations of the CAA and the stations operating permit. On August 7, 2008, a consent decree was filed in the U.S. District Court in full settlement of these CAA claims. Under the terms of the consent decree, DP&L and the other owners of the J.M. Stuart generating station agreed to: (i) certain emission targets related to NOx, SO2 and particulate matter; (ii) make energy efficiency and renewable energy commitments that are conditioned on receiving PUCO approval for the recovery of costs; (iii) forfeit 5,500 SO2 allowances; and (iv) provide funding to a third party non-profit organization to establish a solar water heater rebate program. DP&L and the other owners of the station also entered into an attorneys fee agreement to pay a portion of the Sierra Clubs attorney and expert witness fees. The parties to the lawsuit filed a joint motion on October 22, 2008, seeking an order by the U.S. District Court approving the consent decree with funding for the third party non-profit organization set at $300,000. On October 23, 2008, the U.S. District Court approved the consent decree. On October 21, 2009, the Sierra Club filed with the U.S. District Court a motion for enforcement of the consent decree based on the Sierra Clubs interpretation of the consent decree that would require certain NOx emissions that DP&L has been excluding from its computations to be included for purposes of complying with the emission targets and reporting requirements of the consent decree. DP&L believed that it was properly computing and reporting NOx emissions under the consent decree, but participated in settlement discussions with the Sierra Club. A proposed settlement was agreed to by both parties, approved by the court and then filed into the official record on July 13, 2010. The settlement amends the Consent Decree and sets forth a more detailed and clearer methodology to compute NOx emissions during start-up and shut-down periods. There were no cash payments under the terms of this settlement. The revision 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. Numerous northeast states have filed complaints or have indicated that they will be joining the USEPAs action against Duke Energy and CSP. 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 recently 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 or the financial impact this matter will have on DP&L.
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 NOVs 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. 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 or the financial impact that these matters will have on DP&L.
Other Issues Involving Co-Owned Plants
In 2006, DP&L detected a malfunction with its emission monitoring system at the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) and ultimately determined its SO2 and NOx emissions data were under reported. DP&L has petitioned the USEPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter of 2006. DP&L has sufficient allowances in its general account to cover the understatement. Management does not believe the ultimate resolution of this matter will have a material impact on results of operations, financial condition or cash flows.
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. DP&L has provided data to those agencies regarding its maintenance expenses and operating results. On December 15, 2008, DP&L received a request from the USEPA for additional documentation with respect to those issues and other CAA issues including issues relating to capital expenses and any changes in capacity or output of the units at the O.H. Hutchings Station. During 2009, DP&L continued to submit various other operational and performance data to the USEPA in compliance with its request. DP&L is currently unable to determine the timing, costs or method by which the issues may be resolved and continues to work with the USEPA on this issue.
On November 18, 2009, the USEPA issued a 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 unable to determine the timing, costs or method by which these issues may be resolved and continues to work with the USEPA on this issue.
Regulation Matters Related to Water Quality
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 to the Federal Court of Appeals for the Second Circuit in New York and the Court issued an opinion on January 25, 2007 remanding several aspects of the rule to the USEPA for reconsideration. Several parties petitioned the U.S. Supreme Court for review of the lower court decision. On April 14, 2008, the Supreme Court elected to review the lower court decision on the issue of whether the USEPA can compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Briefs were submitted to the Court in the summer of 2008 and oral arguments were held in December 2008. 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 is developing proposed regulations and anticipates proposing requirements by March 2011 with final rules in place by mid-2012. We are unable to predict the impact this will have on our operations.
Clean Water Act Regulation of Water Discharge
On May 4, 2004, the Ohio EPA issued a final National Pollutant Discharge Elimination System permit (the Permit) for J.M. Stuart Station that continued our authority to discharge water from the station into the Ohio River. During the three-year term of the Permit, we conducted a thermal discharge study to evaluate the technical feasibility and economic reasonableness of water cooling methods other than cooling towers. In December 2006, we submitted an application for the renewal of the 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 the thermal discharge study. Subsequently, representatives from DP&L and the Ohio EPA agreed to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. 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 USEPA has agreed to conduct. If a public hearing is held, it is anticipated that it would be scheduled in the first half of 2011. We are attempting to resolve this issue with both the USEPA and Ohio EPA. The timing for issuance of a final permit is uncertain. DP&L is unable to predict the impact this will have on its operations.
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. DP&L is unable to predict the impact this rulemaking will have on its operations.
Regulation Matters Related to Land Use and Solid Waste Disposal
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 has granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. DP&L believes the chemicals used at its service center building site were appropriately disposed of and have not contributed to the contamination at the South Dayton Dump landfill site. 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. DP&L filed a motion to dismiss the complaint and intends to vigorously defend against any claim that it has any financial responsibility to remediate conditions at the landfill 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. 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 (ANPRM) announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCB). 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. At present, DP&L is unable to predict the impact this initiative will have on its operations.
Regulation of Ash Ponds
During 2008, a major spill occurred at an ash pond owned by the Tennessee Valley Authority (TVA) as a result of a dike failure. The spill generated a significant amount of national news coverage, and support for tighter regulations for the storage and handling of coal combustion products. DP&L has ash ponds at the Killen, O.H. Hutchings and J.M. Stuart Stations which it operates, and also at generating stations operated by others but in which DP&L has an ownership interest.
During 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 October 2009, the USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, the USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds. In May 2010, DP&L responded to the USEPA final inspection report with our plans to address the recommendations.
Similarly, in August 2010, the USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. The draft report relating to the inspection was received in November 2010 and DP&L provided comments on the draft report in December 2010. DP&L is unable to predict the outcome this inspection will have on its operations.
In addition, as a result of the TVA ash pond spill, 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 products including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. DP&L is unable to predict the financial impact of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse impact on operations.
Other Legal 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 jointly 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.
On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, DPL and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim, under which DPL received $3.4 million (net of associated expenses).
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. DP&L, along with other transmission owners in PJM and the Midwest Independent System Operator (MISO) made a compliance filing at FERC on August 19, 2010 that fully demonstrated all payment obligations to and from all parties within PJM and the MISO. The FERC has made no ruling regarding the compliance filing and some parties have requested rehearing by FERC of its May 21, 2010 order. It is expected that any order on the compliance filing and any order regarding the rehearing request will be appealed for Court review. Prior to this final order being issued, DP&L entered into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. Further, in October 2010, DP&L entered into another settlement agreement to settle a portion of SECA amounts still owed to DP&L. With respect to unsettled claims, DP&L management believes it has deferred as a regulatory liability the appropriate amounts that are subject to refund (see SECA net revenue subject to refund within Note 3 of Notes to Consolidated Financial Statements) and therefore the results of this proceeding are not expected to have a material adverse effect on DP&Ls results of operations.
Capital Expenditures for Environmental Matters
Test operations of the FGD equipment on our jointly-owned Conesville Unit 4 were completed in November 2009. The equipment is currently in service.
DPLs construction additions were approximately $151 million, $145 million and $228 million in 2010, 2009 and 2008, respectively, and are expected to approximate $310 million in 2011. Planned construction additions for 2011 relate primarily to new investments in and upgrades to DP&Ls power plant equipment and transmission and distribution system.
DP&Ls construction additions were $148 million, $144 million and $225 million in 2010, 2009 and 2008, respectively, and are expected to approximate $300 million in 2011. Planned construction additions for 2011 relate primarily to new investments in and upgrades to DP&Ls power plant equipment and transmission and distribution system.
All environmental additions made during the past three years pertain to DP&L and approximated $12 million, $21 million and $90 million in 2010, 2009 and 2008, respectively.
ELECTRIC SALES AND REVENUES
The following table sets forth DPLs, DP&Ls and DPLERs electric sales and revenues for the years ended December 31, 2010, 2009 and 2008, respectively.
(a) DP&L sold 4,417 million kWh, 1,464 million kWh and 3,212 million kWh of power to DPLER (a subsidiary of DPL) during the years ended December 31, 2010, 2009 and 2008, 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.
This annual report and other documents that we file with the SEC and other regulatory agencies, as well as other written or oral statements we may make from time to time, contain information based on managements beliefs and include forward-looking statements (within the meaning of the Private Securities Litigation Reform Act of 1995) that involve a number of known and unknown risks, uncertainties and assumptions. These forward-looking statements are not guarantees of future performance and there are a number of factors including, but not limited to, those listed below, which could cause actual outcomes and results to differ materially from the results contemplated by such forward-looking statements. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. These forward-looking statements are generally identified by terms and phrases such as anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will and similar expressions.
Future operating results are subject to fluctuations based on a variety of factors, including but not limited to: unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages; changes in wholesale power sales prices; unusual maintenance or repairs; changes in fuel and purchased power costs, emissions allowance costs, or availability constraints; environmental compliance; and electric transmission system constraints.
The following is a listing of specific risk factors that DPL and DP&L consider to be the most significant to your decision to invest in our securities. If any of these events occur or are continuing, our business, results of operations, financial condition and cash flows could be materially affected.
Our customers have recently begun 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 the PUCO-certified CRES providers and accounted for approximately 97% of the total retail energy supplied by CRES providers within DP&Ls service territory in 2010. Unaffiliated CRES providers also have been certified to provide energy in DP&Ls service territory and during 2010, approximately 800 DP&L customers switched their generation service to these providers. Customer switching from DP&L to DPLER reduces DPLs revenues since the generation rates charged by DPLER are less than the rates charged by DP&L. Increased competition by unaffiliated CRES providers in our 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 a few of the factors that could result in increased switching by customers to PUCO-certified CRES providers in the future:
· Low wholesale price levels may lead to existing CRES providers becoming more active in our service territory, and additional CRES providers entering our territory.
· We could also experience 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 SEC, 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, securities, corporate governance, public disclosure and reporting 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 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&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, 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 POLR 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 by-passable 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 plans, 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 2011 under contract. 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 impact 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. 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 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 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. 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 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 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. These expenditures have been significant in the past and we expect that they could also be significant in the future. Complying with these numerous requirements could at some point become prohibitively expensive and 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 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. We own a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, we are responsible for our pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but have 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 by-passable or additional customer switching occurs, we could have a material adverse impact 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 would likely not be recoverable from customers and could have a material adverse effect on our results of operations, financial condition and cash flows.
If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of Greenhouse Gasses on generation facilities, we could be required to make large additional capital investments.
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 increased interest in legislation and action at the federal and state levels and litigation, including a declaration by the USEPA that GHGs pose a danger to the public health that the USEPA believes allows it to directly regulate greenhouse emissions. There have been various GHG legislative proposals introduced in Congress and there is growing consensus that some form of legislation of GHG emissions will be approved at the federal level that could result in substantial additional costs in the form of taxes or emission allowances. Approximately 99% of the energy we produce is generated by coal. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of CO2 and other GHGs on generation facilities, we could be required to make large additional capital investments. 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 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 impacted 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.
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 impacted 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 status of the USEPAs CAIR. These factors could cause the amount and price of excess emission allowances 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. There has been overall reduced trading activity in the annual NOx and SO2 emission allowance trading markets in recent years. This impact on the emission allowance trading market was due, in large part, to a court order calling into question the USEPAs CAIR annual NOx and SO2 emission allowance trading programs and requiring the USEPA to issue new regulations to address the court order. The adoption of new regulations that could regulate emissions or establish or modify emission allowance trading programs, like the USEPAs proposed Clean Air Transport Rule to replace CAIR, could impact 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 impact 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 impact 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 cleaner 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 the Consent Decree, 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 where suitable alternative materials are not available. Although we believe that any asbestos at our facilities is contained and suitable, 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 PJM RPM base residual auction for the 2013/2014 and 2012/2013 periods cleared at a per megawatt price of $28/day and $16/day, respectively, for our RTO area. Prior to these auctions, the per megawatt prices for the 2011/2012 and 2010/2011 periods were $110/day and $174/day, respectively. 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. 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 the auction prices are sustained at low levels, our results of operations, financial condition and cash flows could have a material adverse impact.
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 impact 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 deferral and 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 defer or recover all of these cost in a timely manner, or the SSO retail riders are by-passable or additional customer switching occurs, our results of operations, financial condition and cash flows could have a material adverse impact.
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. The additional costs charged to DP&L for new large transmission approved projects were immaterial in 2010 and are not expected to be material in 2011. 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 can, and currently is recovering these allocated costs from its SSO retail customers through the TCRR rider.
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, select debt of DPL and DP&L is currently rated investment grade by various rating agencies. If the rating agencies were to rate DPL and DP&L below investment grade, we would likely be required to pay a higher interest rate under certain existing and future financings and our potential pool of investors and funding sources would likely decrease. Our credit ratings also govern the collateral provisions of certain of our contracts, and a below investment grade credit rating by one of the rating agencies could require us to post cash collateral under these 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 impact 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, potentially increasing 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 have a material adverse impact.
Our stock price may fluctuate on account of a number of factors, many of which are beyond our control.
The market price of DPLs common stock has fluctuated over a relatively wide range. Over the past three years, the market price of our common stock has fluctuated with a low of $19.16 and a high of $30.18. Our common stock in recent years has experienced significant price and volume variations that have often been unrelated to our operating performance. Over the previous year, the global markets have increasingly been characterized by substantially increased volatility in companies in a number of industries and in the broader markets. The market price of our common stock may continue to significantly fluctuate in the future and may be affected adversely by factors such as actual or anticipated change in our operating results, acquisition activity, changes in financial estimates by securities analysts, general market conditions, rumors and other factors, which factors may increase price volatility and be exacerbated by continued disruption in the global markets at large.
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 disproportionately impacted 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.
The exercise of warrants would increase the number of common shares outstanding and increase our common share dividend costs, thus affecting any existing guidance on earnings per share and adversely affecting our financial condition and cash flows.
DPLs warrant holders can exercise their warrants to purchase shares of DPL common stock at their discretion until March 12, 2012. As of the date of this report, the number of outstanding warrants is 1.7 million. As a result, DPL could be required to issue up to 1.7 million common shares in exchange for the receipt of the exercise price of $21.00 per share or pursuant to a cashless exercise process. The exercise of warrants would increase the number of common shares outstanding and increase our common share dividend payments.
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 implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002 (the Act). Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors to ensure continued compliance with Section 404 of the Act. 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 impact 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 impact 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 has issued a roadmap for the transition by U.S. public companies to the use of International Financial Reporting Standards (IFRS) promulgated by the International Accounting Standards Board that could result in significant changes to our accounting and reporting, such as in the treatment of regulatory assets and liabilities and property. Under the SECs proposed roadmap, we could be required to prepare financial statements in accordance with IFRS in 2015. The SEC expects to make a determination in 2011 regarding the mandatory adoption of IFRS. We are currently assessing the impact 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 impact. In addition, we have employee compensation plans that reward the performance of our employees. While we seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing, and although we have policies and procedures in place to mitigate excessive risk-taking by employees; 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, 2011. 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 and terrorism could adversely affect our business.
Man-made problems, such as human error, computer viruses, terrorism, theft and sabotage, may disrupt our operations and harm our operating results. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In the course of our business, we also store and use certain of our customers, employees and others personal information and other confidential and sensitive information. Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover them in a timely way, we could be unable to fulfill critical business functions and 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. These events could have a material adverse effect on our results of operations, financial condition and cash flows. Our third party service providers that provide critical business functions or have access to sensitive and confidential information and other data may also be vulnerable to security breaches and other man-made problems that could have an adverse effect on us. In addition, our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our business. Any such disruption could result in a material decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse effect on our results of operations, financial condition and cash flows. The continued threat of terrorism and heightened security and military action in response to this threat, or any future acts of terrorism, may cause further disruptions to the economies of the United States and other countries and create further uncertainties or otherwise materially harm our results of operations, financial condition and cash flows.
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 loan or advance funds to DPL. In addition, DP&L is regulated by the PUCO that 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 pay cash to DPL pursuant to these broad powers. While we do not expect any 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 impact on DPLs results of operations, financial condition and cash flows.
Information relating to our properties is contained in Item 1 ELECTRIC OPERATIONS AND FUEL SUPPLY and Note 4 of Notes to Consolidated 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 with the Bank of New York, 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, 2010, cannot be reasonably determined.
As we have previously disclosed, on or about June 24, 2004, the SEC commenced a formal investigation into the issues raised by a memorandum that had been sent on March 10, 2004, by DPLs and DP&Ls Corporate Controller at the time to the Chairman of the Audit Committee of our Board of Directors expressing the Corporate Controllers concerns, perspectives and viewpoints regarding financial reporting and governance issues within DPL and DP&L. On May 7, 2010, DPL received confirmation from the SECs Division of Enforcement that it had completed its investigation as to DPL and did not intend to recommend any action at this time.
The following additional information is incorporated by reference into this Item: (i) information about the legal and other proceedings contained in Item 1 COMPETITION AND REGULATION of Part 1 of this Annual Report on Form 10-K under the subheading Ohio Retail Rates and (ii) information about the legal proceedings contained in Item 8 Note 16 of Notes to Consolidated Financial Statements of Part II of this Annual Report on Form 10-K under the subheadings Litigation Involving Co-Owned Plants, Notices of Violation Involving Co-Owned Plants and Notices of Violation Involving Wholly-Owned Plants of the section entitled Litigation, Notices of Violation and Other Matters Related to Air Quality and under the subheading Regulation of Waste Disposal under the sections entitled Regulation Matters Related to Land Use and Solid Waste Disposal.
As of February 15, 2011, there were 19,792 holders of record of DPL common equity, excluding individual participants in security position listings. The following table presents the high and low per share sales prices for DPL common stock as reported by the New York Stock Exchange for each quarter of 2010 and 2009:
DP&Ls common stock is held solely by DPL and, as a result, is not listed for trading on any stock exchange.
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 impacted DP&Ls ability to pay cash dividends and, as of December 31, 2010, DP&Ls retained earnings of $616.9 million were all available for DP&L common stock dividends payable to DPL.
DPL paid regular quarterly cash dividends of $0.3025 and $0.2850 per share on our common stock during 2010 and 2009, respectively. The annualized dividend rate was $1.21 per share in 2010 and $1.14 per share in 2009.
On December 8, 2010, DPLs Board of Directors authorized a quarterly dividend rate increase of approximately 10%, increasing the quarterly dividend per DPL common share from $0.3025 to $0.3325, effective with the next dividend declaration. If this dividend rate were maintained, the annualized dividend would increase from $1.21 per share to $1.33 per share. Additional information concerning dividends paid on DPL common stock is set forth under Selected Quarterly Information in Item 8 Financial Statements and Supplementary Data.
Information regarding DPLs equity compensation plans as of December 31, 2010 is disclosed in Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, which incorporates such information by reference from DPLs proxy statement for the 2011 Annual Meeting of Shareholders.
The following table details the repurchase by DPL of its common shares during the fourth quarter of 2010:
(1) Based on a calendar month.
(2) Comprises shares purchased as part of DPLs 2010 repurchase program and shares surrendered to DPL by employees to satisfy individual tax withholding obligations upon vesting of equity awards that are settled in DPL common stock. Shares totaling 3,494 were surrendered during the fourth quarter of 2010 to satisfy these individual tax withholding obligations.
(3) Average price paid per share reflects the individual trade price of repurchases under DPLs current repurchase program as well as the closing price of DPL common stock on the vesting dates of the equity awards.
(4) On October 27, 2010, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may repurchase up to $200 million of its common stock from time to time in the open market, through private transactions or otherwise. During the fourth quarter of 2010, DPL repurchased approximately 2.04 million shares of its common stock at an average price per share of $25.75. This Stock Repurchase Program will run through December 31, 2013 but may be modified or terminated at any time without notice.
The graph below matches DPLs cumulative 5-year total shareholder return on common stock with the cumulative total returns of the Dow Jones US Industrial Average index, the S&P Utilities index and the S&P Electric Utilities index. The graph tracks the performance of a $1,000 investment in our common stock and in each index (with the reinvestment of all dividends) from December 31, 2005 to December 31, 2010.
The stock price performance included in this graph is not necessarily indicative of future stock price performance.