Progress Energy 10-K 2010
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2009
For the transition period from to
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Ac.
Indicate by check mark whether each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 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 to 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 registrants were 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in PART III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” 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 Act).
As of June 30, 2009, the aggregate market value of the voting and nonvoting common equity of Progress Energy held by nonaffiliates was $10,535,128,179. As of June 30, 2009, the aggregate market value of the common equity of PEC held by nonaffiliates was $0. All of the common stock of PEC is owned by Progress Energy. As of June 30, 2009, the aggregate market value of the common equity of PEF held by nonaffiliates was $0. All of the common stock of PEF is indirectly owned by Progress Energy.
As of February 22, 2010, each registrant had the following shares of common stock outstanding:
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Progress Energy and PEC definitive proxy statements for the 2010 Annual Meeting of Shareholders are incorporated into PART III, Items 10, 11, 12 , 13 and 14 hereof.
This combined Form 10-K is filed separately by three registrants: Progress Energy, PEC and PEF (collectively, the Progress Registrants). Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants.
PEF meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format permitted by General Instruction I (2) to such Form 10-K.
TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
GLOSSARY OF TERMS
We use the words “Progress Energy,” “we,” “us” or “our” with respect to certain information to indicate that such information relates to Progress Energy, Inc. and its subsidiaries on a consolidated basis. When appropriate, the parent holding company or the subsidiaries of Progress Energy are specifically identified on an unconsolidated basis as we discuss their various business activities.
The following abbreviations, acronyms or initialisms are used by the Progress Registrants:
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
In this combined report, each of the Progress Registrants makes forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-K that are not historical facts are forward looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.
In addition, examples of forward-looking statements discussed in this Form 10-K include, but are not limited to, 1) statements made in PART I, Item 1A, “Risk Factors” and 2) PART II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the following headings: a) “Strategy” about our future strategy and goals; b) “Results of Operations” about trends and uncertainties; c) “Liquidity and Capital Resources” about operating cash flows, future liquidity requirements and estimated capital expenditures through the year 2012; and d) “Other Matters” about the effects of new environmental regulations, changes in the regulatory environment, meeting anticipated demand in our regulated service territories, potential nuclear construction and our synthetic fuels tax credits.
Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and energy policy; our ability to recover eligible costs and earn an adequate return on investment through the regulatory process; the ability to successfully operate electric generating facilities and deliver electricity to customers; the impact on our facilities and businesses from a terrorist attack; the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; our ability to meet current and future renewable energy requirements; the inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, regulatory and financial risks; the financial resources and capital needed to comply with environmental laws and regulations; risks associated with climate change; weather and drought conditions that directly influence the production, delivery and demand for electricity; recurring seasonal fluctuations in demand for electricity; the ability to recover in a timely manner, if at all, costs associated with future significant weather events through the regulatory process; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; the Progress Registrants’ ability to control costs, including operations and maintenance expense (O&M) and large construction projects; the ability of our subsidiaries to pay upstream dividends or distributions to Progress Energy, Inc. holding company (the Parent); current economic conditions; the ability to successfully access capital markets on favorable terms; the stability of commercial credit markets and our access to short- and long-term credit; the impact that increases in leverage or reductions in cash flow may have on each of the Progress Registrants; the Progress Registrants’ ability to maintain their current credit ratings and the impacts in the event their credit ratings are downgraded; the investment performance of our nuclear decommissioning trust (NDT) funds; the investment performance of the assets of our pension and benefit plans and resulting impact on future funding requirements; the impact of potential goodwill impairments; our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K (Section 29/45K); and the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements. Many of these risks similarly impact our nonreporting subsidiaries.
These and other risk factors are detailed from time to time in the Progress Registrants’ filings with the SEC. Many, but not all, of the factors that may impact actual results are discussed in Item 1A, “Risk Factors,” which you should carefully read. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on the Progress Registrants.
Progress Energy, Inc. is a public utility holding company primarily engaged in the regulated electric utility business. Headquartered in Raleigh, N.C., it owns, directly or indirectly, all of the outstanding common stock of its utility subsidiaries and varying percentages of other nonregulated subsidiaries. As discussed in Note 3, most nonregulated business operations have been divested in recent years. In this report, Progress Energy, which includes the Parent and its subsidiaries on a consolidated basis, is at times referred to as “we,” “our” or “us.” When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself. The Parent was incorporated on August 19, 1999, initially as CP&L Energy, Inc. and became the holding company for PEC on June 19, 2000. We acquired PEF through our November 2000 acquisition of its parent, Florida Progress Corporation (Florida Progress).
As a registered holding company, we are subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). Included within its broad authority, the FERC’s approval is required prior to any merger involving a public utility and prior to the disposition of any utility asset with a market value in excess of $10 million. The FERC prohibits market participants from intentionally or recklessly making any fraudulent or misleading statements with regard to transactions subject to the FERC’s jurisdiction.
Our reportable segments are PEC and PEF, which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 19 for information regarding the revenues, income and assets attributable to our business segments.
The Utilities have more than 22,000 megawatts (MW) of regulated electric generation capacity and serve approximately 3.1 million retail electric customers as well as other load-serving entities. The Utilities operate in retail service territories that have historically had population growth higher than the U.S. average. However, like other parts of the United States, our service territories and business have been negatively impacted by the current economic conditions. The timing and extent of the recovery of the economy cannot be predicted. PEC’s greater proportion of commercial and industrial customers, combined with PEF’s greater proportion of residential customers, creates a balanced customer base. We are dedicated to meeting the growth needs of our service territories and delivering reliable, competitively priced energy from a diverse portfolio of power plants.
For the year ended December 31, 2009, our consolidated revenues were $9.885 billion and our consolidated assets at year-end were $31.236 billion.
In 2009, we concentrated on strategies to address current economic conditions and the ongoing public policy debate on energy and the environment. We continued our efforts toward implementing our balanced solution strategy of energy efficiency, alternative energy and state-of-the-art power generation. The utility industry as a whole faces significant cost pressures and lower retail energy sales. We focused on continuous business excellence, cost management and operational efficiency to help offset lower energy sales at the Utilities.
In 2009, PEF successfully sought and received interim and limited rate relief and nuclear cost recovery in Florida. However, in January 2010, in response to a base rate case PEF filed with the Florida Public Service Commission (FPSC) in 2009, the FPSC voted to grant PEF no increase in base rates above the approximately $132 million annual
revenue requirement that had been previously awarded in 2009 as limited rate relief for the repowered Bartow Plant. We believe the PEF revenue level approved is inadequate given our current costs of providing customers with reliable service, anticipated costs to responsibly prepare for their future energy needs and PEF’s right by law to a reasonable opportunity to recover its operating costs and return on invested capital. Consequently, we are currently reviewing our regulatory options in Florida. As a result of the FPSC’s decision, Fitch Ratings, Moody’s Investors Services, Inc. and Standard and Poor’s Rating Services have indicated that they believe the risk related to Florida’s regulatory environment has increased. This perceived increased risk, along with the revenue requirements level approved in the FPSC decision, has caused the rating agencies to put certain credit ratings of PEF, and in some cases the Parent and PEC, on negative watch. See MD&A – “Liquidity and Capital Resources – Credit Rating Matters” for additional information regarding our credit ratings.
While we have not made a final determination on nuclear construction, in 2009 we continued to take steps to keep open the option of building a plant or plants at Shearon Harris Nuclear Plant (Harris) in North Carolina and at a greenfield site in Levy County, Florida (Levy). We have focused on Levy given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce greenhouse gas (GHG) emissions, as well as existing state legislative policy, which is supportive of nuclear projects. PEF has received two of the three key approvals (with the issuance of a combined license (COL) by the United States Nuclear Regulatory Commission (NRC) remaining) and entered into an engineering, procurement and construction (EPC) agreement for the two proposed Levy units. In 2009, the NRC indicated it would process PEF’s limited work authorization request following COL issuance. This resulted in a minimum 20-month in-service schedule shift for the Levy units. As discussed in “Nuclear Matters – Potential New Construction,” additional schedule shifts are likely. In light of the regulatory schedule shift and other factors, our anticipated capital expenditures for Levy will be significantly less in the near term than previously planned. Later in 2010, PEF will file its annual nuclear cost-recovery filing with the FPSC, which will reflect our latest plan regarding Levy.
During 2009, there were a number of state and federal initiatives related to energy and environmental policy. With the state, federal and international focus on global climate change, we are preparing for a carbon-constrained future. We are expanding and enhancing our demand-side management (DSM), energy-efficiency and energy conservation programs. We continue to actively pursue alternative energy projects. We have executed contracts to purchase approximately 320 MW of electricity generated from solar, biomass and municipal solid waste sources. We announced our intention to embark on a major coal-to-gas fleet modernization in North Carolina by retiring approximately 1,500 MW of older coal-fired units by the end of 2017 and building combined-cycle gas. This will provide rate base growth while reducing our carbon emissions. We also placed into service pollution control equipment (or scrubbers) on PEC’s Mayo Plant and PEF’s Crystal River Unit No. 5 (CR5). Additionally, we were notified of our selection for grant negotiations under The American Recovery and Reinvestment Act’s Smart Grid technology development grant program. The submission of an application and the notification for award negotiations are not a commitment to accept federal funds but are necessary steps to keep the option open. We are currently evaluating the provisions of the law and assessing the conditions imposed by participation in the grant program.
The Progress Registrants’ annual reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge through the Investors section of our Web site at www.progress-energy.com. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The public may read and copy any material we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information regarding the operations of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains a Web site, www.sec.gov, containing reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
The Investors section of our Web site also includes our corporate governance guidelines and code of ethics as well as the charters of the following committees of our board of directors: Executive; Audit and Corporate Performance; Corporate Governance; Finance; Operations and Nuclear Oversight; Nuclear Project Oversight; and Organization
and Compensation. This information is available in print to any shareholder who requests it. Requests should be directed to: Shareholder Relations, Progress Energy, Inc., 410 S. Wilmington Street, Raleigh, NC 27601. Information on our Web site is not incorporated herein and should not be deemed part of this Report.
To our knowledge, there is currently no enacted or proposed legislation in North Carolina, South Carolina or Florida that would give the Utilities’ retail customers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. However, the Utilities compete with suppliers of other forms of energy in connection with their retail customers.
Although there is no pending legislation at this time, if the retail jurisdictions served by the Utilities become subject to deregulation, the recovery of “stranded costs” could become a significant consideration. Stranded costs primarily include the generation assets of utilities whose value in a competitive marketplace would be less than their current book value, as well as above-market purchased power commitments to qualified facilities (QFs). Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs. Assessing the amount of stranded costs for a utility requires various assumptions about future market conditions, including the future price of electricity.
Our largest stranded cost exposure is for PEF’s purchased power commitments with QFs, under which PEF has future minimum expected capacity payments through 2025 of $4.5 billion (See Notes 22A and 22B). PEF was obligated to enter into these contracts under provisions of the Public Utilities Regulatory Policies Act of 1978. PEF continues to seek ways to address the impact of escalating payments under these contracts. However, the FPSC allows for full recovery of the retail portion of the cost of power purchased from QFs. PEC does not have significant future minimum expected capacity payments under their purchased power commitments with QFs.
The Utilities compete with other utilities and merchant generators for bulk power sales and for sales to municipalities and cooperatives.
Increased competition in the wholesale electric utility industry and the availability of transmission access could affect the Utilities’ load forecasts, plans for power supply and wholesale energy sales and related revenues. Wholesale energy sales will be impacted by the extent to which additional generation is available to sell to the wholesale market and the ability of the Utilities to attract new wholesale customers and to retain current wholesale customers who have existing contracts with PEC or PEF.
In June 2009, PEC executed a contract extension with its largest municipal wholesale customer, Public Works Commission of the City of Fayetteville, N.C. The 20-year agreement extends the current contract, representing more than 500 MW of electricity load, through 2032.
Enacted in 2005, the Energy Policy Act of 2005 (EPACT) contains key provisions affecting the electric power industry, including competition among generators of electricity. The FERC has implemented and is considering a number of related regulations to implement EPACT that may impact, among other things, requirements for reliability, QFs, transmission information availability, transmission congestion, security constrained dispatch, energy market transparency, energy market manipulation and behavioral rules. In addition to EPACT, other policies and orders issued by the FERC have supported increased competition within the electric generation industry. EPACT clarified and expanded the FERC’s authority to assure that markets operate fairly without imposing new, mandatory intrusion on state authorities.
In February 2007, the FERC issued Order No. 890 adopting a final rule designed to 1) strengthen the pro forma open access transmission tariff (OATT) to ensure that it achieves its original purpose of remedying undue discrimination; 2) provide greater specificity in the pro forma OATT to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect and facilitate the FERC’s enforcement; and 3) increase
transparency in the rules applicable to planning and use of the transmission system. One of the most significant revisions to the pro forma OATT relates to the development of consistent methodologies for calculating available transfer capability, which determines whether transmission customers can access alternative power supplies. Other significant revisions include: changes to the transmission planning process; reform of energy and generator imbalance penalties; adoption of a “conditional firm” component to long-term point-to-point transmission service and reform of existing requirements for the provision of redispatch service; reform of rollover rights policy; clarification of tariff ambiguities; and increased transparency and customer access to information.
As transmission providers with an OATT on file with the FERC, PEC and PEF are required to comply with the requirements of the rule. A major requirement of the rule was to file a revised pro forma OATT on July 13, 2007. PEC and PEF made the required FERC filing, and both are currently operating under the new tariff. On December 28, 2007, the FERC issued Order No. 890-A granting requests for rehearing and making clarifications to Order No. 890. PEC and PEF made compliance filings on March 17, 2008, in order to meet the requirements of Order 890-A. The FERC approved PEC's and PEF's Order 890-A filings on March 30, 2009.
Effective for PEC on July 1, 2008, and for PEF on January 1, 2008, the Utilities moved from either fixed-revenue requirement or fixed-rate OATT rates to formula-based OATT rates. Under the formula-based rates, the transmission rates are updated each year based on actual costs. The switch to formula-based rates increased PEC’s 2008 revenues by $7 million and increased PEF’s 2008 revenues by $2 million. The rate structure will have a greater impact on PEF in 2011 when all of PEF’s wholesale customers become subject to the new structure. The Utilities filed updated OATT rates in 2009 that increased PEC’s 2009 revenues by $4 million and PEF’s by $2 million.
Certain details related to the rule, such as the precise methodology that will be used to calculate available transfer capability, remain to be determined, and thus it is difficult to make a determination of the overall effect of Order No. 890 on the Utilities’ transmission operations or wholesale marketing function. However, on a preliminary basis, the rule is not anticipated to have a significant impact on the Utilities’ financial results. Nonetheless, the final rule is anticipated to include a wide range of provisions addressing transmission services, and as the new tariff is implemented there is likely to be a significant impact on the Utilities’ transmission operations, planning and wholesale marketing functions.
PEC and PEF are subject to regulation by the FERC with respect to transmission service, including generator interconnection service for facilities making sales for resale and wholesale sales of electric energy. On December 7, 2007, PEC and other major transmission-owning utilities in the Southeast submitted a proposal to FERC for a new regional grid planning process designed to meet FERC directives under Order No. 890 applicable to planning and use of the transmission system. FERC has approved both PEC's and PEF’s regional grid planning processes subject to modification. PEF and PEC filed compliance filings with FERC on October 7, 2008, and December 17, 2008, respectively. PEC received approval from the FERC in January 2010, and PEF is still awaiting FERC approval.
The FERC requires that entities desiring to make wholesale sales of electricity at market-based rates document that they do not possess market power. Market power is exercised when an entity profitably drives up prices through its control of a single activity, such as electricity generation, where it controls a significant share of the total capacity available to the market. The FERC has established screening measures for such determinations. Given the difficulty PEC believed it would experience in passing one of the screens, PEC revised its market-based rate tariffs in 2005 to restrict PEC to sales outside of its control area and peninsular Florida, and filed a new cost-based tariff for sales within PEC’s control area. Accordingly, PEC and PEF make wholesale sales of electricity at cost-based rates in areas inside of PEC’s control area and peninsular Florida and at market-based rates in areas outside of PEC’s control area and peninsular Florida. We do not anticipate that the operations of the Utilities will be materially impacted by this market-based rates decision.
REGIONAL TRANSMISSION ORGANIZATIONS
The FERC’s Order 2000 established national standards for regional transmission organizations (RTOs) and advocated the view that regulated, unbundled transmission would facilitate competition in both wholesale and retail electricity markets. The Utilities previously participated in RTO efforts, but are not currently active in these efforts due to the FERC’s termination of both the GridSouth Transco, LLC (GridSouth) and the GridFlorida RTO proceedings. GridSouth was terminated by the GridSouth participants due to not reaching a consensus on creating a
southeastern RTO. GridFlorida was terminated by the FPSC and the FERC due to the conclusion that it was not beneficial to jurisdictional customers. PEC’s recorded investment in GridSouth totaled $15 million at December 31, 2009. Excluding the immaterial South Carolina retail portion, the GridSouth costs will be fully amortized and recovered by 2012. PEF fully recovered its development costs in GridFlorida from retail ratepayers through base rates.
PEC has nonexclusive franchises with varying expiration dates in most of the municipalities in North Carolina and South Carolina in which it distributes electricity. In North Carolina, franchises generally continue for 60 years. In South Carolina, franchises continue in perpetuity unless terminated according to certain statutory methods. The general effect of these franchises is to provide for the manner in which PEC occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. Of these 240 franchises, the majority covers 60-year periods from the date enacted, and 45 have no specific expiration dates. Of the franchise agreements with expiration dates, 15 expire during the period 2010 through 2014, and the remaining agreements expire between 2015 and 2069. PEC also provides service within a number of municipalities and in all of the unincorporated areas within its service area without franchise agreements.
PEF has nonexclusive franchises with varying expiration dates in 110 of the Florida municipalities in which it distributes electricity. PEF also provides service to 11 other municipalities and in all of the unincorporated areas within its service area without franchise agreements. The general effect of these franchises is to provide for the manner in which PEF occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. The franchise agreements cover periods ranging from 10 to 30 years with the majority covering 30-year periods from the date enacted. Of the 110 franchise agreements, 40 expire between 2010 and 2014, and the remaining agreements expire between 2015 and 2037.
HOLDING COMPANY REGULATION
The Parent is a registered public utility holding company subject to regulation by the FERC under PUHCA 2005, including provisions relating to the establishment of intercompany extensions of credit, sales, acquisitions of securities and utility assets, and services performed by PESC. Under PUHCA 2005, the FERC also has authority over accounting and record retention and cost allocation jurisdiction at the election of the holding company system or the state utility commissions with jurisdiction over its utility subsidiaries.
The Utilities are subject to regulation by a number of federal regulatory agencies, including the Department of Energy (DOE), the North American Electric Reliability Corporation (NERC), the NRC and the United States Environmental Protection Agency (EPA).
The FERC has certified the NERC as the electric reliability organization that will propose and enforce mandatory reliability standards for the bulk power electric system. Included in this certification was a provision for the delegation of authority to audit, investigate and enforce reliability standards in particular regions of the country by entering into delegation agreements with regional entities. In addition, the regional entities have the ability to formulate additional reliability standards in their respective regions, which are required to supplement and be more stringent than the NERC reliability standards. The SERC Reliability Corporation (SERC) and the Florida Reliability Coordinating Council (FRCC) are the regional entities for PEC and PEF, respectively.
PEC and PEF are currently subject to certain reliability standards as registered users, owners and operators of the bulk power system. We expect existing reliability standards to migrate to more definitive and enforceable requirements over time and additional NERC and regional reliability standards to be approved by the FERC in
coming years requiring us to take additional steps to remain compliant. The financial impact of mandatory compliance cannot currently be determined. Failure to comply with the reliability standards could result in the imposition of fines and civil penalties. If we are unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on our financial condition, results of operations and liquidity.
During 2008, PEC self-reported to the SERC three noncompliances with voluntary standards. PEC submitted and completed mitigation plans for these noncompliances with voluntary standards. PEC does not expect enforcement actions on noncompliances to voluntary standards. During 2008, PEC also self-reported to the SERC a violation of a mandatory standard and filed and completed a mitigation plan. PEC and the SERC have reached a settlement agreement on this violation and expect the settlement agreement to be submitted to the FERC for approval during 2010.
During 2009, PEC self-reported to the SERC three violations of mandatory standards. PEC has submitted mitigation plans to the SERC and is currently implementing these mitigation plans. PEC expects to enter into settlement discussions with the SERC for 2009 violations during the first quarter of 2010.
In 2010, PEC self-reported to the SERC four violations of mandatory standards. PEC is developing mitigation plans for submittal to the SERC during the first quarter of 2010.
None of the noncompliances or violations noted above nor the costs of executing the mitigation plans are expected to have a significant impact on our overall compliance efforts, results of operations or liquidity.
During 2008, PEF self-reported to the FRCC four violations of mandatory standards. PEF has filed mitigation plans for the four mandatory violations and completed three of the mitigation plans. The fourth mitigation plan is on schedule and is expected to be completed during 2010. PEF and the FRCC have entered into settlement discussions related to these four violations and expect a settlement to be filed with the FERC during 2010.
During 2009, PEF self-reported to the FRCC eight violations of mandatory standards. PEF has submitted mitigation plans to the FRCC and is currently implementing these mitigation plans. PEF expects to enter into settlement discussions with the FRCC for 2009 violations during the first quarter of 2010.
In 2010, PEF self-reported to the FRCC eight violations of mandatory standards. PEF is developing mitigation plans for submittal to the FRCC during the first quarter of 2010.
None of the violations noted above nor the costs of executing the mitigation plans are expected to have a significant impact on our overall compliance efforts, results of operations or liquidity.
The Utilities’ nuclear generating units are regulated by the NRC under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974. The NRC is responsible for granting licenses for the construction, operation and retirement of nuclear power plants and subjects these plants to continuing review and regulation. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. See “Nuclear Matters.”
The Utilities are also subject to regulation by the EPA. See “Environmental.”
PEC is subject to regulation in North Carolina by the North Carolina Utilities Commission (NCUC), and in South Carolina by the Public Service Commission of South Carolina (SCPSC). PEF is subject to regulation in Florida by the FPSC. The Utilities are regulated by their respective regulatory bodies with respect to, among other things, rates and service for electricity sold at retail; retail cost recovery of unusual or unexpected expenses, such as severe storm costs; and issuances of securities. The underlying concept of utility ratemaking is to set rates at a level that allows
the utility to collect revenues equal to its cost of providing service plus earn a reasonable rate of return on its invested capital, including equity.
Retail Rate Matters
Each of the Utilities’ state utility commissions authorize retail “base rates” that are designed to provide the respective utility with the opportunity to earn a reasonable rate of return on its “rate base,” or net investment in utility plant. These rates are intended to cover all reasonable and prudent expenses of constructing, operating and maintaining the utility system, except those covered by specific cost-recovery clauses.
In PEC’s most recent rate cases in 1988, the NCUC and the SCPSC each authorized a return on equity of 12.75 percent. The Clean Smokestacks Act enacted in North Carolina in 2002 (Clean Smokestacks Act) froze PEC’s retail base rates in North Carolina through December 31, 2007, with provisions that if PEC had experienced extraordinary events beyond its control, PEC could have petitioned for a rate increase. Since 2007, PEC’s current North Carolina base rates have continued subject to traditional cost-based rate regulation.
During 2005, the FPSC approved a four-year base rate agreement with PEF. The new base rates took effect the first billing cycle of January 2006 and remained in effect through the last billing cycle of December 2009, with PEF having the sole option to extend the agreement through the last billing cycle of June 2010, which PEF declined to extend. PEF’s base rate agreement also provided for revenue sharing between PEF and its ratepayers with annual adjustment of the threshold and cap amounts. However, PEF’s retail base revenues did not exceed the threshold in 2009 and thus no revenues were subject to the revenue-sharing provisions. The threshold and cap were $1.688 billion and $1.742 billion, respectively, for 2009.
In anticipation of the expiration of its current base rate settlement agreement, PEF filed a proposal with the FPSC in 2009 for an increase in base rates effective with the first billing cycle of January 2010. The $499 million request for increased base rates was based, in part, on PEF’s investments in its generating fleet and its transmission and distribution systems (See Note 7C). In January 2010, the FPSC voted to grant PEF no increase in base rates above the approximately $132 million annual revenue requirements that had been previously awarded in 2009 as limited rate relief for the repowered Bartow Plant. See Note 7C for details regarding the difference between the $499 million increase in base rates requested and the $132 million increase granted. Among other items, the FPSC authorized a return on equity of 10.5 percent. However, we believe the PEF revenue level approved in January 2010 is inadequate given our current costs of providing customers with reliable service, anticipated costs to responsibly prepare for their future energy needs and PEF’s right by law to a reasonable opportunity to recover its operating costs and return on invested capital. Consequently, we are currently reviewing our regulatory options in Florida.
Retail Cost-Recovery Clauses
Each of the Utilities’ state utility commissions allows recovery of certain costs through various cost-recovery clauses, to the extent the respective commission determines in an annual hearing that such costs, including any past over- or under-recovered costs, are prudent. The clauses are in addition to the Utilities’ approved base rates. The Utilities generally do not earn a return on the recovery of eligible operating expenses under such clauses; however, in certain jurisdictions, the Utilities may earn interest on under-recovered costs. Additionally, the commissions may authorize a return for specified investments for energy efficiency and conservation, capacity costs, environmental compliance and utility plant. See MD&A – “Regulatory Matters and Recovery of Costs” for additional discussion regarding cost-recovery clauses.
Costs recovered by the Utilities through cost-recovery clauses, by retail jurisdiction, were as follows:
Fuel, fuel-related costs and certain purchased power costs are eligible for recovery by the Utilities. The Utilities use coal, oil, hydroelectric (PEC only), natural gas and nuclear power to generate electricity, thereby maintaining a diverse fuel mix that helps mitigate the impact of cost increases in any one fuel. Due to the associated regulatory treatment and the method allowed for recovery, changes in fuel costs from year to year have no material impact on operating results of the Utilities, unless a commission finds a portion of such costs to have been imprudent. However, delays between the expenditure for fuel costs and recovery from ratepayers can adversely impact the timing of cash flow of the Utilities.
As discussed more fully in MD&A – “Other Matters – Regulatory Environment,” eligible nuclear costs not previously recoverable through cost-recovery clauses became recoverable in the Florida retail jurisdiction beginning in 2009.
Renewable Energy and Energy-Efficiency Standards
PEC is subject to renewable energy standards at the state level in North Carolina. North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS) establishes minimum standards for the use of energy from specified renewable energy resources or implementation of energy-efficiency measures by the state’s electric utilities beginning with a 3 percent requirement in 2012 and increasing to 12.5 percent in 2021 for regulated public utilities, including PEC. The premium to be paid by electric utilities to comply with the requirements above the cost they would have otherwise incurred to meet consumer demand is to be recovered through an annual clause. The annual amount that can be recovered through the NC REPS clause is capped and once a utility has expended monies equal to the cap, the utility is deemed to have met its obligations under the NC REPS law, regardless of the actual renewables generated or purchased. The law grants the NCUC authority to modify or alter the NC REPS requirements if the NCUC determines it is in the public interest to do so.
Florida energy law enacted in 2008 includes provisions for development of a renewable portfolio standard for Florida utilities. On January 12, 2009, the FPSC approved a draft Florida renewable portfolio standard rule with a goal of 20 percent renewable energy production by 2020. The FPSC provided the draft Florida renewable portfolio standard rule to the Florida legislature in February 2009, but the legislature did not take action in the 2009 session. We cannot predict the outcome of this matter. Until the rulemaking processes are completed, we cannot predict the costs of complying with the law but PEF would be able to recover its reasonable prudent compliance costs.
On December 30, 2009, the FPSC ordered PEF to adopt DSM goals based on enhanced measures, which will result in significantly higher conservation goals. Under the order, PEF’s aggregate conservation goals over the next ten years are: 1,183 Summer MW, 1,072 Winter MW, and 3,488 gigawatt-hours (GWh). PEF has filed a motion for reconsideration with the FPSC to correct what we believe are oversights or errors. If accepted by the FPSC, PEF’s motion would adjust conservation goals over the next ten years to: 808 Summer MW, 933 Winter MW, and 1,792 GWh. The FPSC is expected to make a decision in March 2010. We cannot predict the outcome of this matter.
As a result of the FPSC’s January 11, 2010 base rate approval, PEF may not collect in base rates additional funds for its storm damage reserve. In the event future storms cause the reserve to be depleted, PEF can petition the FPSC for implementation of an interim surcharge to cover any deficiency of its storm reserve. Under Florida law, PEF also may securitize storm costs upon approval by the FPSC. At December 31, 2009, PEF’s storm reserve totaled $136 million.
PEC does not maintain a storm damage reserve account and does not have an ongoing regulatory mechanism, such as a surcharge, to recover storm costs. In the past, PEC has sought and received permission from the SCPSC and NCUC to defer and amortize certain storm recovery costs.
See Note 7 for further discussion of regulatory matters.
The nuclear power industry faces uncertainties with respect to the cost and long-term availability of disposal sites for spent nuclear fuel and other radioactive waste, compliance with changing regulatory requirements, capital outlays for modifications and new plant construction, the technological and financial aspects of decommissioning plants at the end of their licensed lives and requirements relating to nuclear insurance. Nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.
PEC owns and operates four nuclear generating units: Brunswick Nuclear Plant (Brunswick) Unit No. 1 and Unit No. 2, Harris, and Robinson Nuclear Plant (Robinson). The NRC has renewed the operating licenses for all of PEC’s nuclear plants. The renewed operating licenses for Brunswick No. 1 and No. 2, Harris and Robinson expire in September 2036, December 2034, October 2046 and July 2030, respectively.
PEF owns and operates one nuclear generating unit, Crystal River Unit No. 3 (CR3). The NRC operating license for CR3 currently expires in December 2016. On December 18, 2008, PEF submitted an application to the NRC requesting a 20-year renewal of the CR3 operating license. The license renewal application for CR3 is currently under review by the NRC with a decision expected in 2011.
Over time, PEC and PEF have made various modifications of their nuclear facilities to increase the energy output. During CR3’s fueling and maintenance outage that began in September 2009, PEF commenced a project to replace CR3’s steam generators. During preparations to replace the steam generators, workers discovered a delamination within the concrete of the outer wall of the containment structure. PEF is finalizing the root cause determination of the delamination event and the necessary repair plans. At present, PEF does not have a firm return to service date for CR3, the finalized repair estimates and replacement power costs, nor the impact of insurance recovery. However, the costs to repair the delamination and associated costs of an outage extension, such as fuel, purchased power and maintenance, could be material. Based on the current understanding of the cause of the delamination event and the conceptual repair strategy, PEF expects that CR3 will return to service in mid-2010.
The NRC periodically issues bulletins and orders addressing industry issues of interest or concern that necessitate a response from the industry. It is our intent to comply with and to complete required responses in a timely and accurate manner. Any potential impact to company operations will vary and will be dependent upon the nature of the requirement(s).
POTENTIAL NEW CONSTRUCTION
While we have not made a final determination on nuclear construction, we continue to take steps to keep open the option of building a plant or plants. During 2008, PEC and PEF filed COL applications to potentially construct new nuclear plants in North Carolina and Florida (See Item 1A, “Risk Factors”). The NRC estimates that it will take approximately three to four years to review and process the COL applications. We have focused on the potential nuclear plant construction in Florida given the need for more fuel diversity in Florida and anticipated federal and state policies to reduce GHG emissions as well as existing state legislative policy that is supportive of nuclear projects.
On January 23, 2006, we announced that PEC selected a site at Harris to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEC’s application submission. On February 19, 2008, PEC filed its COL application with the NRC for two additional reactors at Harris. On April 17, 2008, the NRC docketed, or accepted for review, the Harris application. Docketing the application does not preclude additional requests for information as the review proceeds; nor does it indicate whether the NRC will issue the license. No petitions to intervene have been admitted in the Harris COL application. We cannot predict the outcome of this matter. If we receive approval from the NRC and applicable state agencies, and if the decisions to build are made, a new plant would not be online until at least 2019.
On December 12, 2006, we announced that PEF selected Levy to evaluate for possible future nuclear expansion. We selected the Westinghouse Electric AP1000 reactor design as the technology upon which to base PEF’s application
submission. In 2007, PEF completed the purchase of approximately 5,000 acres for Levy and associated transmission needs. On July 30, 2008, PEF filed its COL application with the NRC for two reactors. The FPSC issued the final order granting PEF’s petition for the Determination of Need for Levy on August 12, 2008. On October 6, 2008, the NRC docketed, or accepted for review, the Levy nuclear project application. Docketing the application does not preclude additional requests for information as the review proceeds, nor does it indicate whether the NRC will issue the license. On February 24, 2009, PEF received the NRC’s schedule for review and approval of the COL. One joint petition to intervene in the licensing proceeding was filed with the NRC within the required 60-day notice period by the Green Party of Florida, the Nuclear Information and Resource Service and the Ecology Party of Florida. On July 8, 2009, the Atomic Safety and Licensing Board (ASLB) issued a decision accepting three of the 12 contentions submitted. The admitted contentions involved questions about the storage of low-level radioactive waste, the potential impacts of plant construction and operation on the aquifer and surrounding waters and the potential impact of salt water drift from cooling tower operation. PEF’s appeal of the ASLB’s decision was denied and it is expected at this time that a hearing on the contentions will be conducted in 2011. Other COL applicants have received similar petitions raising similar potential contentions. On December 31, 2008, PEF signed an agreement with Westinghouse Electric Company LLC and Stone & Webster, Inc. for the engineering, procurement and construction of two nuclear units at Levy. The contract price for the two Levy units combined is approximately $7.650 billion, part of which is subject to agreed upon escalation factors. The total escalated cost for the two generating units was estimated to be approximately $14 billion in PEF’s petition for the Determination of Need for Levy, including land, plant components, financing costs, construction, labor, regulatory fees and the initial core for the two units. The necessary transmission equipment and approximately 200 miles of transmission lines associated with the project was estimated to cost an additional $3 billion.
In 2009, the NRC indicated it would not process PEF’s limited work authorization request until after COL issuance. This factor alone resulted in a minimum 20-month in-service schedule shift for the Levy units. Additional schedule shifts are likely given, among other things, the permitting and licensing process, state of Florida and macro-economic conditions, and recent FPSC DSM and energy-efficiency goals and other decisions. Uncertainty regarding access to capital on reasonable terms could be another factor to affect the Levy schedule.
The NRC has issued various orders since September 2001 with regard to security at nuclear plants. These orders include additional restrictions on nuclear plant access, increased security measures at nuclear facilities and closer coordination with our partners in intelligence, military, law enforcement and emergency response at the federal, state and local levels. We completed the requirements as outlined in the orders by the committed dates. As the NRC, other governmental entities and the industry continue to consider security issues, it is possible that more extensive security plans could be required.
SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Policy Act of 1982 promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. We will continue to maximize the use of spent fuel storage capability within our own facilities for as long as feasible.
With certain modifications and additional approvals by the NRC, including the installation and/or expansion of on-site dry cask storage facilities at Robinson, Brunswick and CR3, the Utilities’ spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on their respective systems through the expiration of the operating licenses, including any license renewals, for their nuclear generating units. Harris has sufficient storage capacity through the expiration of its renewed operating licenses.
See MD&A – “Other Matters – Nuclear – Spent Nuclear Fuel Matters” and Note 22D, respectively, for discussion of the status of permanent disposal facilities and the Utilities’ contracts with the DOE for spent nuclear fuel storage.
In the Utilities’ retail jurisdictions, provisions for nuclear decommissioning costs are approved by the respective state utility commissions and are based on site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are approved by the FERC. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. See Note 4D for a discussion of the Utilities’ nuclear decommissioning costs.
We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated. The current estimated capital costs associated with compliance with pollution control laws and regulations that we expect to incur are included within MD&A – “Liquidity and Capital Resources – Capital Expenditures” and within MD&A – “Other Matters – Environmental Matters.”
We have a formal environmental management system to manage the environmental aspects and impacts to our businesses, which generally follows the international ISO 14001 standard. We have established a process to identify environmental risks, take prompt action to address these issues and ensure appropriate senior management oversight on a routine basis. Our business units assume daily responsibility for ensuring environmental compliance and are supported by several corporate organizations, including technical environmental professionals, governance and risk management staff and an energy policy and strategy group. The actions of these organizations are guided by our Environmental, Health and Safety Performance Council, which is composed of senior executives. The Environmental, Health and Safety Performance Council provides overall strategic direction, guides corporate environmental policy, monitors environmental regulatory compliance and approves targets that measure, track and drive performance. Our environmental activities are reported to our board of directors’ Operations and Nuclear Oversight Committee. The committee is responsible for climate change oversight and strategy and therefore assesses our plans and activities and makes recommendations to the full board regarding these matters.
HAZARDOUS AND SOLID WASTE MANAGEMENT
The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of legislation. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation.
There are presently hazardous waste sites, including the Ward Transformer site (Ward) and several manufactured gas plant (MGP) sites, with respect to which we have been notified by the EPA, the State of North Carolina or the State of Florida of our potential liability, as a potentially responsible party (PRP). We have accrued costs for the sites to the extent our liability is probable and the costs can be reasonably estimated. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses (See Notes 7 and 21). Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and submit claims for cost recovery where appropriate. The outcome of these potential claims cannot be predicted. While we accrue for probable costs that can be reasonably estimated, based upon the current status of some sites, not all costs can be reasonably estimated or accrued and actual costs may materially exceed our accruals. Material costs in excess of our accruals could have an adverse impact on our financial condition and results of operations.
GLOBAL CLIMATE CHANGE
Global climate change is one of the primary corporate environmental risks identified by our environmental management system. Our risks associated with climate change are discussed under Item 1A, “Risk Factors.”
Growing state, federal and international attention to global climate change may result in the regulation of carbon dioxide (CO2) and other GHGs. The full impact of final legislation, if enacted and additional regulation resulting
from other GHG initiatives cannot be determined at this time; however, we anticipate that it could result in significant rate increases over time to recover the costs of compliance.
As previously discussed under “Recent Developments,” we are preparing for a carbon-constrained future and are actively engaged in helping shape effective policies to address the issue. We are taking steps to address global climate change by changing the way we make electricity through our balanced solution strategy of energy efficiency, alternative energy and state-of-the-art power generation as discussed in MD&A – “Other Matters – Energy Demand.” We continuously evaluate new generation options to determine if they are realistic for the Southeastern United States where our operations are located.
See Note 21 and MD&A – “Other Matters – Environmental Matters” for additional discussion of our environmental matters, including specific environmental issues, the status of the issues, accruals associated with issue resolutions and our associated exposures.
At February 19, 2010, we employed approximately 11,000 full-time employees. Of this total, approximately 2,000 employees at PEF are represented by the International Brotherhood of Electrical Workers. Progress Energy and the International Brotherhood of Electrical Workers entered into a new three-year labor contract that began December 2008. We consider our relationship with employees, including those covered by collective bargaining agreements, to be good.
We have a noncontributory defined benefit retirement (pension) plan for substantially all full-time employees and an employee stock ownership plan among other employee benefits. We also provide contributory postretirement benefits, including certain health care and life insurance benefits, for substantially all retired employees.
At February 19, 2010, PEC and PEF employed approximately 5,500 and 4,000 full-time employees, respectively.
PEC is a regulated public utility founded in North Carolina in 1908 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina. At December 31, 2009, PEC had a total summer generating capacity (including jointly owned capacity) of 12,585 MW. For additional information about PEC’s generating plants, see “Electric – PEC” in Item 2, “Properties.” PEC’s system normally experiences its highest peak demands during the summer, and the all-time system peak of 12,656 megawatt-hours (MWh) was set on August 9, 2007.
PEC’s service territory covers approximately 34,000 square miles, including a substantial portion of the coastal plain of North Carolina extending from the Piedmont to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in western North Carolina in and around the city of Asheville and an area in the northeastern portion of South Carolina. At December 31, 2009, PEC was providing electric services, retail and wholesale, to approximately 1.5 million customers. Major wholesale power sales customers include North Carolina Eastern Municipal Power Agency (Power Agency), North Carolina Electric Membership Corporation and Public Works Commission of the City of Fayetteville, North Carolina. PEC is subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the NRC. No single customer accounts for more than 10 percent of PEC’s revenues.
PEC’s net income available to parent was $513 million, $531 million and $498 million for the years ended December 31, 2009, 2008 and 2007, respectively. PEC’s total assets were $13.502 billion and $13.165 billion at December 31, 2009 and 2008, respectively.
BILLED ELECTRIC REVENUES
PEC’s electric revenues billed by customer class, for the last three years, are shown as a percentage of total PEC electric revenues in the table below:
Major industries in PEC’s service area include chemicals, textiles, paper, food, metals, rubber and plastics, wood products and stone products.
FUEL AND PURCHASED POWER
SOURCES OF GENERATION
PEC’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEC’s customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies.
PEC’s total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table:
PEC is generally permitted to pass the cost of fuel and certain purchased power costs to its customers through fuel cost-recovery clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. See “Commodity Price Risk” under Item 7A, “Quantitative And Qualitative Disclosures About Market Risk” and Item 1A, “Risk Factors.” However, PEC believes that its fuel supply contracts, as described below and in Note 22A, will be adequate to meet its fuel supply needs.
PEC’s average fuel costs per million British thermal units (Btu) for the last three years were as follows:
Changes in the unit price for coal, oil and gas are due to market conditions. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income.
PEC anticipates a burn requirement of approximately 13.5 million tons of coal in 2010. Almost all of the coal will be supplied from Appalachian coal sources and will be primarily delivered by rail.
For 2010, PEC has short-term, intermediate and long-term agreements from various sources for approximately 100 percent of its estimated burn requirements of its coal units. The contracts have expiration dates ranging from one to ten years. PEC will continue to sign contracts of various lengths, terms and quality to meet its expected burn requirements.
As discussed within MD&A – “Results of Operation – Progress Energy Carolina – Operation and Maintenance,” PEC has announced that it intends to permanently shut-down certain coal-fired units representing approximately 30 percent of its coal-fired power generation fleet between 2013 and the end of 2017 as part of a major coal-to-gas modernization strategy. See “Oil and Gas” for planned gas facilities.
Nuclear fuel is processed through four distinct stages. Stages I and II involve the mining and milling of the natural uranium ore to produce a uranium oxide concentrate and the conversion of this concentrate into uranium hexafluoride. Stages III and IV entail the enrichment of the uranium hexafluoride and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
PEC has sufficient uranium, conversion, enrichment and fabrication contracts to meet its nuclear fuel requirement needs for the foreseeable future. PEC’s nuclear fuel contracts typically have terms ranging from three to fifteen years. For a discussion of PEC’s plans with respect to spent fuel storage, see “Nuclear Matters.”
Oil and Gas
Oil and natural gas supply for PEC’s generation fleet is purchased under term and spot contracts from various suppliers and PEC has derivative instruments limit its exposure to price fluctuations. PEC has dual-fuel generating facilities that can operate with both oil and gas. The cost of PEC’s oil and gas is either at a fixed price or determined by market prices as reported in certain industry publications. PEC believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. PEC’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate pipelines. PEC also purchases capacity under other contracts and utilizes transportation for its peaking load requirements.
The NCUC has granted PEC permission to construct two new generating facilities: a 600-MW combined cycle dual-fuel facility at its Richmond County, N.C. generating facility and a 950-MW combined cycle natural gas-fueled facility at a site in Wayne County, N.C. The facilities are expected to be placed in service in 2011 and 2013, respectively. PEC has also filed for approval to construct a 620-MW natural gas-fueled generating facility at a site in New Hanover County, N.C., projected to be placed in service by late 2013 or early 2014.
PEC purchased approximately 3.3 million MWh, 4.8 million MWh and 3.9 million MWh of its system energy requirements during 2009, 2008 and 2007, respectively, under purchase obligations and operating leases and had 1,309 MW of firm purchased capacity under contract during 2009. PEC may need to acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. PEC believes that it can obtain adequate purchased power to meet these needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected.
PEC has three hydroelectric generating plants licensed by the FERC: Walters, Tillery and Blewett. PEC also owns the Marshall Plant, which has a license exemption. The total summer generating capacity for all four units is 225 MW. PEC submitted an application to relicense for 50 years its Tillery and Blewett Plants and anticipates a decision by the FERC in 2010. The Walters Plant license will expire in 2034.
PEF is a regulated public utility founded in Florida in 1899 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. At December 31, 2009, PEF had a total summer generating capacity (including jointly owned capacity) of 10,013 MW. For additional information about PEF’s generatingplants, see “Electric – PEF” in Item 2, “Properties.” PEF’s system normally experiences its highest peak demands during the winter, and the all-time system peak of 10,822 MWh was set on January 11, 2010.
PEF’s service territory covers approximately 20,000 square miles in west central Florida, and includes the densely populated areas around Orlando, as well as the cities of St. Petersburg and Clearwater. PEF is interconnected with 22 municipal and 9 rural electric cooperative systems. At December 31, 2009, PEF was providing electric services, retail and wholesale, to approximately 1.6 million customers. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., Florida Municipal Power Agency, the city of Gainesville, Tampa Electric Company, and Reedy Creek Improvement District. PEF is subject to the rules and regulations of the FERC, the FPSC and the NRC. No single customer accounts for more than 10 percent of PEF’s revenues.
PEF’s net income available to parent was $460 million, $383 million and $315 million for the years ended December 31, 2009, 2008 and 2007, respectively. PEF’s total assets were $13.100 billion and $12.471 billion at December 31, 2009 and 2008, respectively.
BILLED ELECTRIC REVENUES
PEF’s electric revenues billed by customer class, for the last three years, are shown as a percentage of total PEF electric revenues in the table below:
Major industries in PEF’s territory include phosphate rock mining and processing, electronics design and manufacturing, and citrus and other food processing. Other major commercial activities are tourism, health care, construction and agriculture.
FUEL AND PURCHASED POWER
SOURCES OF GENERATION
PEF’s consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEF’s customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies.
PEF’s total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table:
PEF is generally permitted to pass the cost of fuel and certain purchased power to its customers through fuel cost-recovery clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted
with complete certainty. See “Commodity Price Risk” under Item 7A, “Quantitative And Qualitative Disclosures About Market Risk” and Item 1A, “Risk Factors.” However, PEF believes that its fuel supply contracts, as described below and in Note 22A, will be adequate to meet its fuel supply needs.
PEF’s average fuel costs per million Btu for the last three years were as follows:
Changes in the unit price for coal, oil and gas are due to market conditions. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income.
Oil and Gas
Oil and natural gas supply for PEF’s generation fleet is purchased under term and spot contracts from various suppliers and PEF has derivative instruments to limit its exposure to price fluctuations. PEF has dual-fuel generating facilities that can operate with both oil and gas. The cost of PEF’s oil and gas is either at a fixed price or determined by market prices as reported in certain industry publications. PEF believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. PEF’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate pipelines. PEF also purchases capacity under other contracts and utilizes transportation for its peaking load requirements.
PEF anticipates a requirement of approximately 5.5 million tons of coal in 2010. Approximately 60 percent of the coal is expected to be supplied from Appalachian coal sources and 40 percent supplied from coal sources in the Illinois Basin and Colorado. Approximately 30 percent of the coal is expected to be delivered by rail and the remainder by water.
For 2010, PEF has intermediate and long-term contracts from various sources for approximately 100 percent of its estimated burn requirements of its coal units. These contracts have price adjustment provisions and have expiration dates ranging from one to ten years.
PEF purchased approximately 8.7 million MWh, 10.2 million MWh and 11.1 million MWh of its system energy requirements during 2009, 2008 and 2007, respectively, under purchase obligations, operating leases and capital leases and had 1,847 MW of firm purchased capacity under contract during 2009. These agreements include approximately 682 MW of firm capacity under contract with certain QFs. PEF may need to acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. PEF believes that it can obtain adequate purchased power to meet these needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected.
Nuclear fuel is processed through four distinct stages. Stages I and II involve the mining and milling of the natural uranium ore to produce a uranium oxide concentrate and the conversion of this concentrate into uranium hexafluoride. Stages III and IV entail the enrichment of the uranium hexafluoride and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
PEF has sufficient uranium, conversion, enrichment and fabrication contracts to meet its nuclear fuel requirement needs for the foreseeable future. PEF’s nuclear fuel contracts typically have terms ranging from three to fifteen years. For a discussion of PEF’s plans with respect to spent fuel storage, see “Nuclear Matters.”
CORPORATE AND OTHER
Corporate and Other primarily includes the operations of the Parent and PESC. The Parent’s unallocated interest expense is included in Corporate and Other. PESC provides centralized administrative, management and support services to our subsidiaries, which generates essentially all of the segment’s revenues. See Note 18 for additional information about PESC services provided and costs allocated to subsidiaries. This segment also includes miscellaneous nonregulated business areas that do not separately meet the quantitative disclosure requirements as a reportable business segment.
The Corporate and Other segment’s net loss attributable to controlling interests was $216 million, $84 million and $309 million for the years ended December 31, 2009, 2008 and 2007, respectively. Corporate and Other segment total assets were $20.538 billion and $17.483 billion at December 31, 2009 and 2008, respectively, which were primarily comprised of the Parent’s investments in subsidiaries.
Investing in the securities of the Progress Registrants involves risks, including the risks described below, that could affect the Progress Registrants and their businesses, as well as the energy industry in general. Most of the business information, as well as the financial and operational data contained in our risk factors is updated periodically in the reports the Progress Registrants file with the SEC. Before purchasing securities of the Progress Registrants, you should carefully consider the following risks and the other information in this combined Annual Report, as well as the documents the Progress Registrants file with the SEC from time to time. Each of the risks described below could result in a decrease in the value of the securities of the Progress Registrants and your investment therein.
Solely with respect to this Item 1A, “Risk Factors,” unless the context otherwise requires or the disclosure otherwise indicates, references to “we,” “us” or “our” are to each of the individual Progress Registrants, and the matters discussed are generally applicable to each Progress Registrant.
We are subject to fluid and complex government regulations that may have a negative impact on our business, financial condition and results of operations.
We are subject to comprehensive regulation by multiple federal, state and local regulatory agencies, which significantly influences our operating environment and may affect our ability to recover costs from utility customers. We are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of our business, including customer rates, retail service territories, reliability of our transmission system, applicable renewable energy and energy-efficiency standards, environmental compliance, issuances of securities, asset acquisitions and sales, accounting policies and practices, and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws. Changes in laws and regulations as well as changes in federal administrative policy are ongoing and the ultimate costs of compliance cannot be precisely estimated. Such changes could have an adverse impact on our financial condition and results of operations.
The rates that PEC and PEF may charge retail customers for electric power are subject to the authority of state regulators. Accordingly, our profit margins and ability to earn an adequate return on investment could be adversely affected if we do not control and prudently manage costs to the satisfaction of regulators, or if we do not obtain successful outcomes in our regulatory proceedings. Such regulatory decisions may be impacted by economic and public policy considerations within the respective jurisdictions.
The NCUC, the SCPSC and the FPSC each exercise regulatory authority for review and approval of the retail electric power rates charged within its respective state. The Utilities’ state utility commissions approve base rates, which by law must give a utility a reasonable opportunity to recover its operating costs and return on invested capital. They also approve recovery of certain additional costs, known as “pass-through” costs, over and above base rates through cost-recovery clauses, which vary by jurisdiction; examples include fuel costs, certain purchased power costs, qualified nuclear costs and specified environmental costs. The commissions can disagree with our request of appropriate base rates, and can disallow either requested base rates or pass-through recoveries on the grounds that such costs were not reasonable and prudent.
The Utilities expect increased future expenditures in several key areas including, but not limited to, environmental compliance, new and existing generation, transmission and distribution facilities, renewable energy and energy-efficiency standards compliance (as applicable), DSM programs and fuel and other commodities. Such cost increases will be subject to scrutiny from regulators, policymakers and ratepayers. As referenced above, the commissions may disallow any costs that they find unreasonable and imprudent.
Our financial performance depends on the successful operation of electric generating facilities by the Utilities and their ability to deliver electricity to customers.
Operating our electric generating facilities and delivery systems involves many risks, including:
Occurrences of these events could adversely affect our financial condition or results of operations.
Meeting the anticipated demand in our service territories and fulfilling our environmental compliance strategies will require, among other things, modernization of coal generation facilities, the construction within the next decade of new generation facilities and the siting and construction of associated transmission facilities. We may not be able to obtain required licenses, permits and rights-of-way; successfully and timely complete construction; or recover the cost of such new generation and transmission facilities through our base rates or other recovery mechanisms, any of which could adversely impact our financial condition, cash flows or results of operations.>
Meeting the anticipated demand within the Utilities’ service territories and complying with existing and potential environmental laws and regulations will require a balanced approach. The three main elements of this balanced solution are: (1) expanding our energy-efficiency programs; (2) investing in the development of alternative energy resources for the future; and (3) operating state-of-the-art plants that produce energy cleanly and efficiently by modernizing existing plants and pursuing options for building new plants and associated transmission facilities.
The risks of each of the elements of our balanced solution include, but are not limited to, the following:
Energy-Efficiency and New Energy Resources
We are expanding our DSM, energy-efficiency and conservation programs and will continue to pursue additional initiatives as these programs can be effective ways to reduce energy costs, offset the need for new power plants and protect the environment.
We are subject to the risk that our customers may not participate in our conservation programs or that the results from these programs may be less than anticipated. This could impact our compliance with state-mandated energy-efficiency standards as discussed in the risks regarding renewable energy standards. Also, not achieving the energy-efficiency and conservation measurements we assumed in our long-term resource planning could require us to further expand our generation or purchase additional power at prevailing market rates.
We are also subject to the risk that customer participation in these programs or new technologies that impact the quantity and pattern of electricity usage may decrease our electric sales and require us to seek future rate increases to cover our prudently incurred costs.
As discussed further in the risk factor related to renewable energy standards, we are actively engaged in a variety of alternative energy projects. These alternative energy projects may be determined to not be cost-efficient or cost-effective.
Modernization and Construction of Generating Plants
We are currently evaluating our options for new generating plants, including gas and nuclear technologies. In 2009, we announced our intention to retire certain coal-fired units in North Carolina that do not have emission control equipment and to construct new natural gas-fueled units at certain of these facilities. We are also evaluating the possibility of converting certain of these facilities to be fueled by natural gas or biomass. At this time, no definitive decision has been made regarding the construction of nuclear plants.
Decisions to build new power plants and successful completion of such construction projects are based on many factors including:
There is no assurance that we will be able to successfully and timely construct new generation facilities or to expand or modernize existing facilities within our projected budgets or that those expenditures will be recoverable through our base rates or other recovery mechanisms. As with any major construction undertaking, completion could be delayed or prevented, or cost overruns could be incurred, as a result of numerous factors, including shortages of material and labor, labor disputes, weather interferences, difficulties in obtaining necessary licenses or permits or complying with license or permit conditions, and unforeseen engineering, environmental or geological problems. These construction projects are long-term and may involve facility designs that have not been previously constructed or that have not been finalized when that project is commenced. Consequently, the projects potentially could be subject to significant cost increases for labor, materials, scope changes and changes in design. Unsuccessful construction, expansion or modernization efforts could be subject to additional costs and/or the write-off of our investment in the project or improvement.
The construction of new power plants and associated expansion of our transmission system will require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support the construction. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital. For certain new baseload generation facilities, we may pursue joint ventures or similar arrangements with third parties in order to share some of the financing and operational risks, but we cannot be certain we will be able to successfully negotiate any such arrangement. Furthermore, joint ventures or joint ownership arrangements also present risks and uncertainties, including those associated with sharing control over the construction and operation of a facility and reliance on the other party’s financial or operational strength.
Our assumptions regarding future growth and resulting power demand in our service territories may not be realized. Like other parts of the United States, our service territories and business have been negatively impacted by the current economic conditions. The timing and extent of the recovery of the economy cannot be predicted. We may increase our baseload capacity based on anticipated growth levels and have excess capacity if those levels are not realized. The resulting excess capacity may exceed the reserve margins established by the NCUC, SCPSC and FPSC to meet our obligation to serve retail customers and, as a result, may not be recoverable.