SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2012
o TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
(Former name, former address and former fiscal year, if changed since last report)
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 registrants were 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 whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition 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 Exchange Act).
At May 3, 2012, each registrant had the following shares of common stock outstanding:
This combined Form 10-Q 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 H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.
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-Q 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-Q include, but are not limited to, statements made in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) including, but not limited to, statements under the following headings: “Merger” about the proposed merger between Progress Energy and Duke Energy Corporation (Duke Energy) and the impact of the merger on our strategy and liquidity; “Results of Operations” about trends and uncertainties; “Liquidity and Capital Resources” about operating cash flows, future liquidity requirements and estimated capital expenditures; and “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:
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,” in the Progress Registrants’ most recent annual report on Form 10-K, which was filed with the SEC on February 29, 2012, and is updated for material changes, if any, in this Form 10-Q and in our other SEC filings. 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.
PART I. FINANCIAL INFORMATION
PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY d/b/a/ PROGRESS ENERGY CAROLINAS, INC.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
INDEX TO APPLICABLE COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS BY REGISTRANT
Each of the following combined notes to the unaudited condensed interim financial statements of the Progress Registrants are applicable to Progress Energy, Inc. but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF. The notes that are not listed below for PEC or PEF are not, and shall not be deemed to be, part of PEC’s or PEF’s financial statements contained herein.
PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy’s financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to these Combined Notes. 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 is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC).
Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. 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 12 for further information about our segments.
PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC’s subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.
PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC.
These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).
The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants’ financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods.
In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.
Certain amounts for 2011 have been reclassified to conform to the 2012 presentation.
The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.
The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of comprehensive income were as follows:
We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE’s variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity.
Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary for this VIE during 2011 or for the period ended March 31, 2012. No financial or other support has been provided to the VIE during the periods presented.
The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:
The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses.
Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million for each of the three months ended March 31, 2012 and 2011. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.
See discussion of PEC’s variable interests within the Progress Energy section.
PEF has no significant variable interests in VIEs.
On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction and become a wholly owned subsidiary of Duke Energy. The Merger Agreement originally had a termination date of January 8, 2012, which has been extended to July 8, 2012. The Merger Agreement can be extended past July 8, 2012, only by mutual agreement of Progress Energy and Duke Energy.
Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the merger. Accordingly, the adjusted exchange ratio is expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.
The combined company, to be called Duke Energy, will have an 18-member board of directors. The board will be comprised of, subject to their ability and willingness to serve, all 11 current directors of Duke Energy and seven current directors of Progress Energy. At the time of the merger, William D. Johnson, Chairman, President and CEO of Progress Energy, will be President and CEO of Duke Energy, and James E. Rogers, Chairman, President and CEO of Duke Energy, will be the Executive Chairman of the board of directors of Duke Energy, subject to their ability and willingness to serve.
Consummation of the merger is subject to customary conditions, including, among others things, approval by the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission and the SCPSC. Although there are no merger-specific regulatory approvals required in Indiana, Ohio or Florida, the companies will continue to update the public service commissions in those states on the merger, as applicable and as required. The status of these matters is as follows, and we cannot predict the outcome of pending approvals:
Federal Regulatory Approvals
State Regulatory Approvals
The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share. In the fourth quarter of 2011, our board of directors aligned Progress Energy’s dividend payment schedule with that of Duke Energy such that following the closing of the merger, all stockholders of the combined company would receive dividends under the Duke Energy dividend schedule.
Certain substantial changes in ownership of Progress Energy, including the merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 15 in the 2011 Form 10-K).
The Merger Agreement contains certain termination rights for both companies; under specified circumstances we may be required to pay Duke Energy $400 million and Duke Energy may be required to pay us $675 million. In addition, under specified circumstances each party may be required to reimburse the other party for up to $30 million of merger-related expenses.
In connection with the merger, we established an employee retention plan for certain eligible employees. Payments under the plan are contingent upon the consummation of the merger and the employees’ continued employment through a specified time period following the merger. These payments will be recorded as compensation expense following consummation of the merger. We estimate the costs of the retention plan to be $14 million.
In connection with the merger, we offered a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the merger. Approximately 650 employees requested and were approved for separation under the VSP in 2011. The cost of the VSP is estimated to be between $90 million to $100 million, including $65 million to $70 million for PEC and $25 million to $30 million for PEF. If the employee is not required to work for a significant period after the consummation of the merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the merger. If a significant retention period exists, the costs of benefits equal to what would be paid under our existing severance plan will be measured and recorded upon consummation of the merger. Any additional benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.
In addition, we evaluated our business needs for office space after the merger and formulated an exit plan to vacate one of our corporate headquarters buildings. We have begun to gradually vacate the premises and will be fully vacated by January 1, 2013. In December 2011, we executed an agreement with a third party to sublease the building until 2035. The estimated exit cost liability associated with this exit plan is $17 million for us, of which $12 million of expense is attributable to PEC and $5 million to PEF. The exit cost liability will be recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. During the first quarter of 2012, we recorded exit cost liabilities of $3 million for us, of which $2 million of expense is attributable to PEC and $1 million to PEF. At March 31, 2012, the total exit cost liability recorded by us is $8 million, of which $6 million of expense is attributable to PEC and $2 million of expense is attributable to PEF. These costs are included in merger and integration-related costs.
We incurred merger and integration-related costs of $5 million, net of tax, including $3 million, net of tax, and $2 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2012. We incurred merger and integration-related costs of $14 million, net of tax, including $7 million, net of tax, and $7 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2011. These costs are included in operations and maintenance (O&M) expense in our Consolidated Statements of Comprehensive Income.
FAIR VALUE MEASUREMENT AND DISCLOSURES
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends Accounting Standards Codification (ASC) 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 was effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities’ financial position, results of operations or cash flows.
GOODWILL IMPAIRMENT TESTING
In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of
performing a qualitative assessment before calculating the fair value of our reporting units. If it were determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 was effective for us on January 1, 2012 for both prospective interim and annual goodwill tests and will give us the option to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The prospective impact of the adoption is not expected to be significant to our or the Utilities’ financial position, results of operations or cash flows.
DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES
In December 2011, the FASB issued ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” which requires new disclosures to help financial statement users better understand the impact of offsetting arrangements on our balance sheet. The adoption of ASU 2011-11 will add disclosures showing both gross and net information about instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. ASU 2011-11 is effective for us on January 1, 2013, and will be retroactively applied.
We have completed our business strategy of divesting nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. Included in discontinued operations, net of tax are amounts related to adjustments of our prior sales of diversified businesses. These adjustments are generally due to guarantees and indemnifications provided for certain legal, tax and environmental matters. See Note 14B for further discussion of our guarantees. The ultimate resolution of these matters could result in additional adjustments in future periods.
During the three months ended March 31, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $11 million and $(2) million, respectively. Earnings for the three months ended March 31, 2012, relates primarily to an $18 million pre-tax gain from the reversal of certain environmental indemnification liabilities for which the indemnification period has expired.
On January 8, 2011, Progress Energy and Duke Energy entered into the Merger Agreement. See Note 2 for regulatory information related to the merger with Duke Energy.
COST RECOVERY FILINGS
On March 1, 2012, PEC filed with the SCPSC for a $5 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate, driven by the introduction of new, and the expansion of existing, DSM and EE programs. If approved, the increase will be effective July 1, 2012, and will increase residential electric bills by $1.37 per 1,000 kilowatt-hours (kWh). We cannot predict the outcome of this matter.
In September 2009, Crystal River Nuclear Plant Unit 3 (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit’s steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site
identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur during the repair process.
PEF analyzed multiple repair options as well as early decommissioning and believes, based on the information and analyses conducted to date, that repairing the unit is the best option. PEF engaged outside engineering consultants to perform the analysis of possible repair options for the containment building. The consultants analyzed 22 potential repair options and ultimately narrowed those to four. PEF, along with other independent consultants, reviewed the four options for technical issues, constructability, and licensing feasibility as well as cost.
Based on that initial analysis, PEF selected the best repair option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the repair is under way. PEF will update the current estimate as this work is completed.
PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. The decision related to repairing or decommissioning CR3 is complex and subject to a number of unknown factors, including but not limited to, the cost of repair and the likelihood of obtaining NRC approval to restart CR3 after repair. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments.
PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accident but has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through March 31, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. PEF also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.
PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. PEF has not yet received a definitive determination from NEIL about the insurance coverage related to the second delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, PEF has not recorded insurance receivables from NEIL related to the second delamination. Negotiations continue with NEIL regarding coverage associated with the second delamination, and PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.
The following table summarizes the CR3 replacement power and repair costs and recovery through March 31, 2012:
PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.
2012 SETTLEMENT AGREEMENT
On February 22, 2012, the FPSC approved a comprehensive settlement agreement among PEF, the Florida Office of Public Counsel and other consumer advocates. The 2012 settlement agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: PEF’s proposed Levy Nuclear Power Plant (Levy) Nuclear Project cost recovery, the CR3 delamination prudence review then pending before the FPSC, and certain base rate issues. When all of the settlement provisions are factored in, the total increase in 2013 for residential customer bills will be approximately $4.93 per 1,000 kWh, or 4 percent.
Under the terms of the 2012 settlement agreement, PEF will set the residential cost-recovery factor of PEF’s proposed two units at Levy (see “Nuclear Cost Recovery – Levy Nuclear”) at $3.45 per 1,000 kWh effective in the first billing cycle of January 2013 and continuing for a five-year period. PEF will not recover any additional Levy costs from customers through the term of the agreement, or file for any additional recovery before March 1, 2017, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the combined license (COL) and any engineering, procurement and construction (EPC) cancellation costs, if PEF ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose PEF continuing to pursue a COL for Levy. After the five-year period, PEF will true up any actual costs not recovered under the Levy cost-recovery factor.
The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. PEF will have the discretion to accelerate and/or suspend such amortization in full or in part provided that PEF amortizes all of the regulatory asset by December 31, 2016.
Under the terms of the 2012 settlement agreement, PEF will be permitted to recover prudently incurred fuel and purchased power costs through the fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the term of the agreement or the return of CR3 to commercial service. If PEF does not begin repairs of CR3 prior to the end of 2012, PEF will refund replacement power costs on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. The parties to the agreement waive their right to challenge PEF’s recovery of replacement power costs. The parties to the agreement maintain the right to challenge the prudence and reasonableness of PEF’s fuel acquisition and power purchases, and other fuel prudence issues unrelated to the CR3 outage. All prudence issues from the steam generator project inception through the date of settlement approval by the FPSC are resolved.
To the extent that PEF pursues the repair of CR3, PEF will establish an estimated cost and repair schedule with ongoing consultation with the parties to the agreement. The established cost, to be approved by our board of directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between our shareholders and PEF customers up to $400 million. The parties to the agreement agree to discuss the method of recovery of any overruns in excess of $400 million, with final decision by the FPSC if resolution cannot be reached. If the repairs begin prior to the end of 2012, the parties to the agreement waive their rights to challenge PEF’s decision to repair and the repair plan chosen by PEF. In addition, there will be limited rights to challenge recovery of the repair execution costs incurred prior to the final resolution on NEIL coverage. The parties to the agreement will discuss the treatment of any potential gap between NEIL repair coverage and the estimated cost, with final decision by the FPSC if resolution cannot be reached. If the repairs do not begin prior to the end of 2012, the parties to the agreement reserve the right to challenge the prudence of PEF’s repair decision, plan and implementation.
PEF also retains sole discretion and flexibility to retire the unit without challenge from the parties to the agreement. If PEF decides to retire CR3, PEF is allowed to recover all remaining CR3 investments and to earn a return on the CR3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity (ROE) set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. Additionally, any NEIL proceeds received after the settlement will be applied first to replacement power costs incurred after December 31, 2012, with the remainder used to write down the remaining CR3 investments.
Base Rates, Customer Refund and Other Terms
Under the terms of the 2012 settlement agreement, PEF will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million annual increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5 percent. PEF suspended depreciation expense and reversed certain regulatory liabilities associated with CR3 effective on the February 22, 2012 implementation date of the agreement, resulting in a $47 million benefit for the quarter ended March 31, 2012, which reduced O&M expense. Additionally, rate base associated with CR3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. PEF will accrue, for future rate-setting purposes, a carrying charge at a rate of 7.4 percent on the CR3 investment until CR3 is returned to service and placed back into retail rate base. Upon return of CR3 to commercial service, PEF will be authorized to increase its base rates for the annual revenue requirements of all CR3 investments. The parties to the agreement reserve the right to participate in any hearings challenging the appropriateness of PEF’s CR3 revenue requirements. In the month following CR3’s return to commercial service, PEF’s ROE range will increase to 9.7 percent to 11.7 percent. If PEF’s retail base rate earnings fall below the ROE range, as reported on a FPSC-adjusted or pro-forma basis on a PEF monthly earnings surveillance report, PEF may petition the FPSC to amend its base rates during the term of the agreement.
Under the terms of the 2012 settlement agreement, PEF will refund $288 million to customers through the fuel clause. PEF will refund $129 million in each of 2013 and 2014, and an additional $10 million annually to residential and small commercial customers in 2014, 2015 and 2016. At December 31, 2011, a regulatory liability was established for the $288 million to be refunded in future periods. The corresponding charge was recorded as a reduction of 2011 revenues.
The cost of pollution control equipment that PEF installed and has in-service at Crystal River Units 4 and 5 (CR4 and CR5) to comply with the Federal Clean Air Interstate Rule (CAIR) is currently recovered under the Environmental Cost Recovery Clause (ECRC). The 2012 settlement agreement provides for PEF to remove those assets from recovery in the ECRC and transfer those assets to base rates effective with the first billing cycle of January 2014. The related base rate increase will be in addition to the $150 million base rate increase effective January 2013. O&M expense associated with those assets will not be included in the base rates and will continue to be recovered through the ECRC.
The 2012 settlement agreement provides for PEF to continue to recover carrying costs and other nuclear cost recovery clause-recoverable items related to the CR3 uprate project, but PEF will not seek an in-service recovery until nine months following CR3’s return to commercial service. Carrying costs will be recovered through the nuclear cost recovery clause until base rates have been increased for these assets.
The 2012 settlement agreement also allows PEF to continue to reduce amortization expense (cost of removal component) beyond the expiration of the 2010 settlement agreement through the term of the 2012 settlement agreement (see “Cost of Removal Reserve”). Additionally, the 2012 settlement agreement extends PEF’s ability to expedite recovery of the cost of named storms and to maintain a storm reserve at its level as of the implementation date of the agreement, and removed the maximum allowed monthly surcharge established by the 2010 settlement agreement.
COST OF REMOVAL RESERVE
The 2012 and 2010 settlement agreements provide PEF the discretion to reduce amortization expense (cost of removal component) by up to the balance in the cost of removal reserve until the earlier of (a) PEF’s applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 settlement agreement at the end of 2016. For the three months ended March 31, 2012, PEF recognized a $58 million reduction in amortization expense pursuant to the settlement agreements. PEF had eligible cost of removal reserves of $216 million remaining at March 31, 2012, which is impacted by accruals in accordance with PEF’s latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreements.
NUCLEAR COST RECOVERY
In 2008, the FPSC granted PEF’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule for PEF’s proposed Levy project, together with the associated facilities, including transmission lines and substation facilities.
On April 30, 2012, as part of PEF’s annual nuclear cost recovery filing (see “Cost Recovery”), PEF updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current, low natural gas prices, PEF is shifting the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 settlement agreement. Although the scope and overnight cost for Levy – including land acquisition, related transmission work and other required investments – remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.
Along with the FPSC’s annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF’s preferred baseload generation option.
In 2007, the FPSC issued an order approving PEF’s Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3’s gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011 and accepted for review by the NRC on November 21, 2011.
On April 30, 2012, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $152 million, which includes recovery of pre-construction and carrying costs and Capacity Cost-Recovery Clause (CCRC) recoverable O&M expense incurred or anticipated to be incurred during 2013, recovery of $88 million of prior years deferrals in 2013, as well as the estimated actual true-up of 2012 costs associated with the CR3 uprate and Levy projects, as permitted by the 2012 settlement agreement. This results in an increase in the nuclear cost-recovery charge of $2.23 per 1,000 kWh for residential customers, which if approved, would begin with the first January 2013 billing cycle. The FPSC has scheduled hearings in this matter for August 2012, with a decision expected in October 2012. We cannot predict the outcome of this matter.
DEMAND-SIDE MANAGEMENT COST RECOVERY
On July 26, 2011, the FPSC voted to set PEF’s DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener filed a protest to the FPSC’s Proposed Agency Action order, asserting legal challenges to the order. The parties made legal arguments to the FPSC and the FPSC issued an order denying the protest on December 22, 2011. The intervener then filed a notice of appeal of this order to the Florida Supreme Court on January 17, 2012. We cannot predict the outcome of this matter.
On March 29, 2012, PEF announced plans to convert the 1,011-MW Anclote Units 1 and 2 (Anclote) from oil and natural gas fired to 100 percent natural gas fired and requested that the FPSC permit recovery of the estimated $79 million conversion cost through the ECRC. PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (see Note 13B). PEF anticipates that both converted units will be placed in service by the end of 2013. We cannot predict the outcome of this matter.
There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three months ended March 31, 2012 and 2011. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial.
The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders’ proportionate share of the equity of a subsidiary and a VIE (See Note 1C).
The following table presents changes in total equity for the year to date: