10-K 1 form10k-2010.htm 2010 10K form10k-2010.htm f
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-K

 
(Mark One)
 
 
[ X ]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

 
[    ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                                                  to

Commission
File Number
Exact name of registrants as specified in their charters,
state of incorporation, address of principal executive
offices, and telephone number
I.R.S. Employer
Identification Number
 
pgn logo
 
1-15929
Progress Energy, Inc.
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
56-2155481
     
1-3382
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
410 South Wilmington Street
Raleigh, North Carolina  27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
56-0165465
     
1-3274
Florida Power Corporation
d/b/a Progress Energy Florida, Inc.
299 First Avenue North
St. Petersburg, Florida 33701
Telephone: (727) 820-5151
State of Incorporation: Florida
59-0247770


SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class
Name of each exchange on which registered
Progress Energy, Inc.:
 
Common Stock (Without Par Value)
New York Stock Exchange
Carolina Power & Light Company:
None
Florida Power Corporation:
None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Progress Energy, Inc.:
None
Carolina Power & Light Company:
$5 Preferred Stock, No Par Value
 
Serial Preferred Stock, No Par Value
Florida Power Corporation:
None


 
 

 
Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Act.

Progress Energy, Inc. (Progress Energy)
Yes
(X)
No
(   )
Carolina Power & Light Company (PEC)
Yes
(   )
No
(X)
Florida Power Corporation (PEF)
Yes
(   )
No
(X)

Indicate by check mark whether each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Progress Energy
Yes
(   )
No
(X)
PEC
Yes
(   )
No
(X)
PEF
Yes
(X)
No
(   )

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.
 
Progress Energy
Yes
(X)
No
(   )
PEC
Yes
(X)
No
(   )
PEF
Yes
(   )
No
(X)

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).
 
Progress Energy
Yes
(X)
No
(   )
PEC
Yes
(   )
No
(   )
PEF
Yes
(   )
No
(   )

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.
 
Progress Energy
(X)
PEC
(X)
PEF
(X)

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:
 
Progress Energy
Large accelerated filer
(X)
Accelerated filer
(   )
 
Non-accelerated filer
(   )
Smaller reporting company
(   )
         
PEC
Large accelerated filer
(   )
Accelerated filer
(   )
 
Non-accelerated filer
(X)
Smaller reporting company
(   )
         
PEF
Large accelerated filer
(   )
Accelerated filer
(   )
 
Non-accelerated filer
(X)
Smaller reporting company
(   )

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
 
Progress Energy
Yes
(   )
No
(X)
PEC
Yes
(   )
No
(X)
PEF
Yes
(   )
No
(X)

As of June 30, 2010, the aggregate market value of the voting and nonvoting common equity of Progress Energy held by nonaffiliates was $11,477,572,820. As of June 30, 2010, 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, 2010, 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, 2011, each registrant had the following shares of common stock outstanding:
 
Registrant
Description
Shares
Progress Energy
Common Stock (Without Par Value)
293,541,665
PEC
Common Stock (Without Par Value)
159,608,055
PEF
Common Stock (Without Par Value)
100

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Progress Energy and PEC definitive proxy statements for the 2011 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
 
PART I
BUSINESS
   
RISK FACTORS
   
UNRESOLVED STAFF COMMENTS
   
PROPERTIES
   
LEGAL PROCEEDINGS
   
(REMOVED AND RESERVED)
   
 
EXECUTIVE OFFICERS OF THE REGISTRANTS
   
PART II
MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
   
SELECTED FINANCIAL DATA
   
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
   
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
   
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
   
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
   
CONTROLS AND PROCEDURES
   
OTHER INFORMATION
   
PART III
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
   
EXECUTIVE COMPENSATION
   
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
   
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
   
PRINCIPAL ACCOUNTING FEES AND SERVICES
   
PART IV
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
   

 
1

 

GLOSSARY OF TERMS

We use the words “Progress Energy,” “we,” “us” or “our” to indicate that certain 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:
 
TERM
DEFINITION
   
401(k)
Progress Energy 401(k) Savings & Stock Ownership Plan
AFUDC
Allowance for funds used during construction
ARO
Asset retirement obligation
ASC
FASB Accounting Standards Codification
ASLB
Atomic Safety and Licensing Board
the Asset Purchase Agreement
Agreement by and among Global, Earthco and certain affiliates, and the Progress Affiliates as amended on August 23, 2000
ASU
Accounting Standards Update
Audit Committee
Audit and Corporate Performance Committee of Progress Energy’s board of directors
BART
Best Available Retrofit Technology
Base Revenues
Non-GAAP measure defined as operating revenues excluding clause recoverable regulatory returns, miscellaneous revenues and fuel and other pass-through revenues
Brunswick
PEC’s Brunswick Nuclear Plant
Btu
British thermal unit
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CAVR
Clean Air Visibility Rule
CCRC
Capacity Cost-Recovery Clause
CERCLA or Superfund
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Smokestacks Act
North Carolina Clean Smokestacks Act
the Code
Internal Revenue Code
CO2
Carbon dioxide
COL
Combined license
Corporate and Other
Corporate and Other segment primarily includes the Parent, Progress Energy Service Company and miscellaneous other nonregulated businesses
CR1 and CR2
PEF’s Crystal River Units No. 1 and No. 2 coal-fired steam turbines
CR3
PEF’s Crystal River Unit No. 3 Nuclear Plant
CR4 and CR5
PEF’s Crystal River Units No. 4 and No. 5 coal-fired steam turbines
CVO
Contingent value obligation
D.C. Court of Appeals
U.S. Court of Appeals for the District of Columbia Circuit
DOE
United States Department of Energy
DSM
Demand-side management
Duke Energy
Duke Energy Corporation
Earthco
Four coal-based solid synthetic fuels limited liability companies of which three were wholly owned
ECCR
Energy Conservation Cost Recovery Clause
ECRC
Environmental Cost Recovery Clause
EE
Energy efficiency
EIP
Equity Incentive Plan
EPA
United States Environmental Protection Agency
EPC
Engineering, procurement and construction
ESOP
Employee Stock Ownership Plan
 
 
2

 
 
FASB
Financial Accounting Standards Board
FDEP
Florida Department of Environmental Protection
FERC
Federal Energy Regulatory Commission
FGT
Florida Gas Transmission Company, LLC
Fitch
Fitch Ratings
the Florida Global Case
U.S. Global, LLC v. Progress Energy, Inc. et al.
Florida Progress
Florida Progress Corporation
FPSC
Florida Public Service Commission
Funding Corp.
Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Global
U.S. Global, LLC
GWh
Gigawatt-hours
Harris
PEC’s Shearon Harris Nuclear Plant
IPP
Progress Energy Investor Plus Plan
kV
Kilovolt
kVA
Kilovolt-ampere
kWh
Kilowatt-hours
Levy
PEF’s proposed nuclear plant in Levy County, Fla.
LIBOR
London Inter Bank Offered Rate
MACT
Maximum achievable control technology
MD&A
Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in PART II, Item 7 of this Form 10-K
Medicare Act
Medicare Prescription Drug, Improvement and Modernization Act of 2003
the Merger
Proposed merger between Progress Energy and Duke Energy
the Merger Agreement
Agreement and Plan of Merger, dated as of January 8, 2011, by and among Progress Energy and Duke Energy
MGP
Manufactured gas plant
MW
Megawatts
MWh
Megawatt-hours
Moody’s
Moody’s Investors Service, Inc.
NAAQS
National Ambient Air Quality Standards
NC REPS
North Carolina Renewable Energy and Energy Efficiency Portfolio Standard
NCUC
North Carolina Utilities Commission
NDT
Nuclear decommissioning trust
NEIL
Nuclear Electric Insurance Limited
NERC
North American Electric Reliability Corporation
North Carolina Global Case
Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC
NOx
Nitrogen oxides
NRC
Nuclear Regulatory Commission
O&M
Operation and maintenance expense
OATT
Open Access Transmission Tariff
OCI
Other comprehensive income
Ongoing Earnings
Non-GAAP financial measure defined as GAAP net income attributable to controlling interests after excluding discontinued operations and the effects of certain identified gains and charges
OPEB
Postretirement benefits other than pensions
the Parent
Progress Energy, Inc. holding company on an unconsolidated basis
PEC
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
PEF
Florida Power Corporation d/b/a Progress Energy Florida, Inc.
PESC
Progress Energy Service Company, LLC
Power Agency
North Carolina Eastern Municipal Power Agency
 
 
3

 
 
PPACA
Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act
Preferred Securities
7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust
Preferred Securities Guarantee
Florida Progress’ guarantee of all distributions related to the Preferred Securities
Progress Affiliates
Five affiliated coal-based solid synthetic fuels facilities
Progress Energy
Progress Energy, Inc. and subsidiaries on a consolidated basis
Progress Registrants
The reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF
PRP
Potentially responsible party, as defined in CERCLA
PSSP
Performance Share Sub-Plan
QF
Qualifying facility
RCA
Revolving credit agreement
Reagents
Commodities such as ammonia and limestone used in emissions control technologies
REPS
Renewable energy portfolio standard
Robinson
PEC’s Robinson Nuclear Plant
ROE
Return on equity
RSU
Restricted stock unit
SCPSC
Public Service Commission of South Carolina
Section 29
Section 29 of the Code
Section 29/45K
General business tax credits earned after December 31, 2005 for synthetic fuels production in accordance with Section 29
Section 45K
Section 45K of the Code
Section 316(b)
Section 316(b) of the Clean Water Act
(See Note/s “#”)
For all sections, this is a cross-reference to the Combined Notes to the Financial Statements contained in PART II, Item 8 of this Form 10-K
SERC
SERC Reliability Corporation
S&P
Standard & Poor’s Rating Services
SO2
Sulfur dioxide
Subordinated Notes
7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp.
Tax Agreement
Intercompany Income Tax Allocation Agreement
the Trust
FPC Capital I
the Utilities
Collectively, PEC and PEF
VIE
Variable interest entity
Ward
Ward Transformer site located in Raleigh, N.C.
Ward OU1
Operable unit for stream segments downstream from the Ward site
Ward OU2
Operable unit for further investigation at the Ward facility and certain adjacent areas
   


 
4

 

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) “Merger” about the proposed merger between Progress Energy and Duke Energy Corporation (Duke Energy) (the Merger) and the impact of the Merger on our strategy and liquidity; b) “Strategy” about our future strategy and goals; c) “Results of Operations” about trends and uncertainties; d) “Liquidity and Capital Resources” about operating cash flows, future liquidity requirements and estimated capital expenditures; and e) “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:
 
·  
our ability to obtain the approvals required to complete the Merger and the impact of compliance with material restrictions or conditions potentially imposed by our regulators;
·  
the risk that the Merger is terminated prior to completion and results in significant transaction costs to us;
·  
our ability to achieve the anticipated results and benefits of the Merger;
·  
the impact of business uncertainties and contractual restrictions while the Merger is pending;
·  
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, safety, 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);
 
 
5

 
 
·  
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 should be read carefully. 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.
 

 
6

 

PART I
 
ITEM 1.
 
GENERAL
 
ORGANIZATION
 
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, PEC and PEF. 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).
 
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. 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. 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.
 
For the year ended December 31, 2010, our consolidated revenues were $10.190 billion and our consolidated assets at year-end were $33.054 billion.
 
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 website at www.progress-energy.com. Information on our website is not incorporated herein and should not be deemed part of this Report.  These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished with 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 website, www.sec.gov, containing reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
 
RECENT DEVELOPMENTS
 
On January 8, 2011, 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 continue as a wholly owned subsidiary of Duke Energy (the Merger). Both companies’ boards of directors have unanimously approved the Merger Agreement. However, consummation of the Merger is subject to customary conditions, including, among other things, approval of the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approval, to the extent required,
 
 
7

 
 
from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission, the Nuclear Regulatory Commission (NRC), the North Carolina Utilities Commission (NCUC), the Kentucky Public Service Commission and the South Carolina Public Service Commission (SCPSC), the Florida Public Service Commission (FPSC), the Indiana Utility Regulatory Commission, and the Ohio Public Utilities Commission . See Item IA, “Risk Factors,” MD&A – “Introduction – Merger,” and Note 25 for additional information related to the Merger.
 
On June 1, 2010, the FPSC approved a settlement agreement between PEF and interveners, with the exception of the Florida Association for Fairness in Ratemaking, to the 2009 rate case and a PEF-proposed accounting order. Among other provisions, under the terms of the settlement agreement, PEF will maintain base rates at current levels through the last billing cycle of 2012. The settlement agreement also provides that PEF will have the discretion to reduce amortization expense (cost of removal component) in 2010, 2011 and 2012. The settlement agreement also provides that if PEF’s actual retail base rate earnings fall below a 9.5 percent return on equity (ROE) on an adjusted or pro forma basis, as reported on a historical 12-month basis during the term of the agreement, PEF may seek general, limited or interim base rate relief, or any combination thereof. Prior to requesting any such relief, PEF must have reflected on its referenced surveillance report associated amortization expense reductions of at least $150 million. The settlement agreement does not preclude PEF from requesting the FPSC to approve the recovery of costs (a) that are of a type which traditionally and historically would be, have been or are presently recovered through cost-recovery clauses or surcharges, or (b) that are incremental costs not currently recovered in base rates, which the legislature or FPSC determines are clause recoverable, or (c) which are recoverable through base rates under the nuclear cost-recovery legislation or the FPSC’s nuclear cost-recovery rule. See Note 7C for additional provisions of the settlement agreement.
 
In September 2009, PEF’s nuclear generating unit, Crystal River Unit No. 3 (CR3), began an outage for normal refueling and maintenance as well as its uprate project to increase the unit’s generating capability and to replace two steam generators. During preparations to replace the steam generators, we discovered a delamination within the concrete of the outer wall of the containment structure, which has resulted in an extension of the outage. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. Nuclear safety remains our top priority, and our plans and actions will continue to reflect that commitment. A number of factors affect the return to service date, including regulatory reviews by the NRC and other agencies, emergent work, final engineering designs, testing, weather and other developments. PEF anticipates recovering the costs related to the extended outage through a combination of insurance and customer rates. See “Nuclear Matters – General” and Note 7C.
 
Although we have not made a final determination on new nuclear construction, we have taken steps to keep open the option of building one or more 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 NRC remaining) and entered into an engineering, procurement and construction (EPC) agreement for the two proposed Levy units. As discussed in “Nuclear Matters – Potential New Construction,” with the 2010 amendment to the EPC agreement, PEF will postpone major construction activities at Levy until after the NRC issues the COL. If the licensing schedule remains on track and if the decision to build is made, the first of PEF’s two proposed units could be in service in 2021. The second unit could be in service 18 months later.
 
We are preparing for a carbon-constrained future given the state, federal and international focus on global climate change. We are expanding and enhancing our demand-side management (DSM), energy-efficiency (EE) and energy conservation programs. In 2010, we accepted a grant from the United States Department of Energy (DOE) for $200 million in federal matching infrastructure funds in support of our smart grid initiatives. In addition to providing the Utilities real-time information about the state of their electric grids, the smart grid transition will enable customers to better understand and manage their energy use, and will provide for more efficient integration of renewable energy resources. We continue to actively pursue alternative energy projects. We have executed contracts to purchase 311 MW of electricity generated from solar, biomass and municipal solid waste sources. We have adopted a major coal-to-gas modernization strategy whereby the 11 remaining coal-fired generating facilities in North Carolina that do not have scrubbers would be retired by the end of 2014 (prior to the end of their useful lives) and their approximately 1,500 MW of generating capacity replaced with new natural gas-fueled facilities. This will provide rate base growth
 
 
8

 
 
while reducing our carbon emissions. After 2014, PEC will continue to operate its Roxboro, Mayo and Asheville coal-fired plants in North Carolina, which have state-of-the-art emission controls.
 
COMPETITION
 
RETAIL COMPETITION
 
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.
 
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 $4.7 billion (See Notes 22A and 22B). PEF was obligated to enter into these contracts under provision 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 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 its purchased power commitments with QFs.
 
WHOLESALE COMPETITION
 
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.
 
The FERC adopted final rules 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.
 
Certain details related to the rules, 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 the new rules 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.
 
 
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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. FERC has approved, subject to modification, regional grid planning processes covering PEC and PEF. PEC and PEF made compliance filings with FERC in 2008. 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.
 
FRANCHISE MATTERS
 
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 PEC’s 240 franchises, the majority covers 60-year periods from the date enacted, and 45 have no specific expiration dates. Of the PEC franchise agreements with expiration dates, 13 expire during the period 2011 through 2015, and the remaining agreements expire between 2016 and 2070. 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 111 of the Florida municipalities in which it distributes electricity. PEF also provides service to 10 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 PEF franchise agreements cover periods ranging from 10 to 30 years with the majority covering 30-year periods from the date enacted. Of PEF’s 111 franchise agreements, 39 expire between 2011 and 2015, and the remaining agreements expire between 2016 and 2040.
 
REGULATORY MATTERS
 
HOLDING COMPANY REGULATION
 
The Parent is a registered public utility holding company subject to regulation by the FERC, including provisions relating to the establishment of intercompany extensions of credit, sales, acquisitions of securities and utility assets, and services performed by PESC. 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.
 
UTILITY REGULATION
 
FEDERAL REGULATION
 
The Utilities are subject to regulation by a number of federal regulatory agencies, including the DOE, the North American Electric Reliability Corporation (NERC), the NRC and the United States Environmental Protection Agency (EPA).
 
 
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Reliability Standards
 
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 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 electric 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 electric system in the future, it could have a material adverse effect on our financial condition, results of operations and liquidity.
 
PEC and PEF have self-reported to the SERC and Florida Reliability Coordinating Council noncompliances and violations with the voluntary and mandatory standards from time to time. The noncompliances and violations have led to the development and implementation of mitigation plans at the Utilities. 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.
 
Nuclear
 
The Utilities’ nuclear generating units are regulated by the NRC. 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.”
 
Environmental
 
The Utilities are also subject to regulation by the EPA. See “Environmental.”
 
STATE REGULATION
 
PEC is subject to regulation in North Carolina by the NCUC, and in South Carolina by the 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 authorizes 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 ROE of 12.75 percent.
 
In PEF’s most recent rate case settlement agreement approved by the FPSC in 2010, the FPSC authorized PEF the opportunity to earn a ROE of up to 11.5 percent.
 
 
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On September 14, 2010, the FPSC approved a reduction to PEF’s AFUDC rate, from 8.848 percent to 7.44 percent, based on PEF’s updated authorized ROE. This new rate will be used for all purposes except for nuclear recoveries with original need petitions submitted on or before December 31, 2010, as permitted by FPSC regulations.
 
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:
 
·  
North Carolina Retail – fuel costs, the fuel and other portions of purchased power (capacity costs for purchases from dispatchable QFs are also recoverable), costs of new DSM and EE programs, costs of commodities such as ammonia and limestone used in emissions control technologies (Reagents), and eligible renewable energy costs;
 
·  
South Carolina Retail – fuel costs, certain purchased power costs, costs of Reagents, sulfur dioxide (SO2) and nitrogen oxides (NOx) emission allowance expenses, and costs of new DSM and EE programs; and
 
·  
Florida Retail – fuel costs, purchased power costs, capacity costs, qualified nuclear costs, energy conservation expense and specified environmental costs, including Clean Air Interstate Rule (CAIR) compliance costs, and SO2 and NOx emission allowance expenses.
 
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. PEF is obligated to file for a midcourse recovery between annual fuel hearings in the event its estimated over- or under-recovery of fuel costs meets or exceeds a threshold of 10 percent of estimated total retail fuel revenues and, accordingly, has the ability to mitigate the cash flow impacts due to the timing of recovery of fuel and purchased power costs.
 
Renewable Energy and Energy-Efficiency Standards
 
PEC is allowed to recover the costs of DSM and EE programs in North Carolina and South Carolina through an annual DSM and EE clause in each jurisdiction. PEC is allowed to capitalize DSM and EE costs intended to produce future benefits. In addition, the NCUC and the SCPSC have approved other forms of financial incentives for DSM and EE programs, including the recovery of net lost revenues and a performance incentive. DSM programs include, but are not limited to, any program or initiative that shifts the timing of electricity use from peak to nonpeak periods and includes load management, electricity system and operating controls, direct load control, interruptible load and electric system equipment and operating controls. EE programs include any equipment, physical or program change implemented after January 1, 2007, that results in less energy used to perform the same function. PEC has implemented a series of DSM and EE programs and will continue to pursue additional programs, which must be approved by the respective utility commissions. We cannot predict the outcome of DSM and EE filings currently pending approval or whether the implemented programs will produce the expected operational and economic results.
 
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

 
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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, regardless of the actual renewables generated or purchased. The NCUC has the 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. The FPSC provided a draft Florida renewable portfolio standard rule with a goal of 20 percent renewable energy production by 2020 to the Florida legislature in February 2009, but the legislature has not taken action on the draft rule. 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 and 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. As subsequently revised by the FPSC in 2010, PEF’s aggregate conservation goals over the next 10 years are: 1,134 Summer MW, 1,058 Winter MW, and 3,205 gigawatt-hours (GWh). PEF filed a revised proposed DSM plan on November 29, 2010, which would result in 1,540 GWh of energy savings from 2011-2019, seven times more than PEF’s historic goals. We cannot predict the outcome of this matter.
 
See Note 7 for further discussion of regulatory matters.
 
NUCLEAR MATTERS
 
GENERAL
 
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, CR3. The NRC operating license for CR3 currently expires in December 2016. On March 9, 2009, the NRC docketed, or accepted for review, PEF’s application for a 20-year renewal on the operating license for CR3, which, if approved, would extend the operating license through 2036, the current useful life used by the FPSC in base rates. 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 to 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, we discovered a delamination within the concrete of the outer wall of the containment structure. After a comprehensive analysis, we have determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when we created an opening to accommodate the replacement of the unit’s steam generators. We expect to complete repairs in March, and return the unit to service following successful completion of post-repair testing and start-up activities in April 2011. Nuclear safety remains our top priority, and our plans and actions will continue to reflect that commitment. A number of factors affect the return to service date, including regulatory reviews by the NRC and
 
 
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other agencies, emergent work, final engineering designs, testing, weather and other developments. PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages as well as accidental property damage. PEF’s insurer has confirmed that the CR3 delamination event is a covered accident. PEF is working with its insurer for recovery of applicable repair costs and replacement power. See Note 7C.
 
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 new nuclear construction, we continue to take steps to keep open the option of building one or more plants. During 2008, PEC and PEF filed COL applications to potentially construct new nuclear plants in North Carolina and Florida. The NRC estimates that it will take approximately three to four years to review and process the COL applications. We have focused on PEF’s potential construction at Levy 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.
 
LEVY
 
In 2006, we announced that PEF selected a greenfield site at 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.
 
In 2008, the FPSC issued a final order granting PEF’s petition for a Determination of Need for Levy. In 2009, the Power Plant Siting Board, comprised of the governor and the Cabinet, issued the Levy site certification that addresses permitting, land use and zoning, and property interests and replaces state and local permits. Certification grants approval for the location of the power plant and its associated facilities such as roadways and electrical transmission lines carrying power to the electrical grid, among others. Certification does not include licenses required by the federal government.
 
On July 30, 2008, PEF filed its COL application with the NRC for two reactors, which was docketed, or accepted for review, by the NRC on October 6, 2008. 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 60-day notice period by the Green Party of Florida, the Nuclear Information and Resource Service and the Ecology Party of Florida. On April 20-21, 2009, the Atomic Safety Licensing Board (ASLB) heard oral arguments on whether any of the joint interveners’ proposed contentions will be admitted in the Levy COL proceeding. On July 8, 2009, the ASLB issued a decision accepting three of the 12 contentions submitted. The admitted contentions involved questions about the potential safety and environmental impact of 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. In April 2010, the ASLB dismissed the contention regarding the safety of storage of low-level radioactive waste; however, interveners have resubmitted their contention regarding the potential safety of storage of low-level waste, which is being considered by the ASLB. PEF’s appeal of the ASLB’s 2009 decision was denied and a hearing on the remaining contentions will be conducted in 2012. Other COL applicants have received similar petitions raising similar potential contentions. We cannot predict the outcome of this matter.
 
PEF also completed and submitted a Limited Work Authorization request for Levy concurrent with the COL application. PEF’s initial schedule anticipated performing certain site work pursuant to the Limited Work Authorization prior to COL receipt. However, in 2009, the NRC Staff determined that certain schedule-critical work that PEF had proposed to perform within the scope of the Limited Work Authorization will not be authorized until the NRC issues the COL. Consequently, excavation and foundation preparation work will be shifted until after COL
 
 
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issuance. This factor alone resulted in a minimum 20-month schedule shift later than the projected in-service dates for Units No. 1 and No. 2 of June 2016 and June 2017, respectively, included in the petition for a Determination of Need. Subsequent changes in regulatory and economic conditions have resulted in additional schedule shifts. These conditions include the permitting and licensing process, national and state economic conditions, recent FPSC DSM goals and the resulting impact on ratepayers, and other FPSC decisions. Uncertainty regarding PEF’s access to capital on reasonable terms, its ability to secure joint owners and increasing uncertainty surrounding carbon regulation and its costs could be other factors to affect the Levy schedule.
 
As disclosed in PEF’s 2010 nuclear cost-recovery filing, the schedule shifts will reduce the near-term capital expenditures for the project and also reduce the near-term impact on customer rates (See Note 7C). PEF will postpone major construction activities on the project until after the NRC issues the COL, which is expected to be in 2013 if the current licensing schedule remains on track. The schedule shifts will also allow more time for certainty around federal climate change policy. We believe that continuing, although at a slower pace than initially anticipated, is a reasonable and prudent course at this early stage of the project. Taking into account cost, potential carbon regulation, fossil fuel price volatility and the benefits of fuel diversification, we consider Levy to be PEF’s preferred baseload generation option. 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, public, regulatory and political support; adequate financial cost-recovery mechanisms; adequate levels of joint owner participation; customer rate impacts; project feasibility, including comparison to other generation options, DSM and EE programs; and availability and terms of capital financing. If the licensing schedule remains on track and if the decision to build is made, the first of the two proposed units could be in service in 2021. The second unit could be in service 18 months later.
 
PEF signed the EPC agreement on December 31, 2008, with Westinghouse Electric Company LLC and Stone & Webster, Inc. for two Westinghouse AP1000 nuclear units to be constructed at Levy. More than half of the approximate $7.650 billion contract price is fixed or firm with agreed upon escalation factors. The EPC agreement includes various incentives, warranties, performance guarantees, liquidated damage provisions and parent guarantees designed to incent the contractor to perform efficiently. For termination without cause, the EPC agreement contains exit provisions with termination fees, which may be significant, that vary based on the termination circumstances. We executed an amendment to the EPC agreement in 2010 due to the schedule shifts previously discussed. Additionally, in light of the schedule shifts in the Levy nuclear project, PEF may incur fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. As a result of the analysis, PEF will continue with selected components of the long lead time equipment. Work has been suspended on the remaining long lead time equipment items and PEF has been in suspension negotiations with the selected equipment vendors, which we anticipate concluding by the end of the first quarter of 2011. In its 2010 nuclear cost-recovery filing, approved by the FPSC on October 26, 2010, PEF included for rate-making purposes a point estimate of potential Levy disposition fees and charges of $50 million, subject to true-up. However, the amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed. We cannot predict the outcome of this matter.
 
The total escalated cost for the two generating units was estimated in PEF’s petition for the Determination of Need for Levy to be approximately $14 billion. This total cost estimate included land, plant components, financing costs, construction, labor, regulatory fees and the initial core for the two units. An additional $3 billion was estimated for the necessary transmission equipment and approximately 200 miles of transmission lines associated with the project. PEF’s 2010 nuclear cost-recovery filing included an updated analysis that demonstrated continued feasibility of the Levy project with PEF’s current estimated range of total escalated cost, including transmission, of $17.2 billion to $22.5 billion. The filed estimated cost range primarily reflects cost escalation resulting from the schedule shifts. Many factors will affect the total cost of the project and once PEF receives the COL, it will further refine the project timeline and budget. As previously discussed, we will continue to evaluate the Levy project on an ongoing basis.
 
Florida regulations allow investor-owned utilities such as PEF to recover the retail portion of prudently incurred site selection costs, preconstruction costs and the carrying cost on construction cost balances of a nuclear power plant prior to commercial operation. The costs are recovered on an annual basis through the Capacity Cost-Recovery 
 
 
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Clause (CCRC). Such amounts will not be included in a utility’s rate base when the plant is placed in commercial operation. The nuclear cost-recovery rule also has a provision to recover costs should the project be abandoned after the utility receives a final order granting a Determination of Need. These costs include any unrecovered retail portion of construction work in progress at the time of abandonment and any other prudent and reasonable exit costs. In addition, the rule requires the FPSC to conduct an annual prudence review of the reasonableness and prudence of all such costs, including construction costs, and such determination shall not be subject to later review except upon a finding of fraud, intentional misrepresentation or the intentional withholding of key information by the utility (See Note 7C).
 
HARRIS
 
In 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, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application. If we receive approval from the NRC and applicable state agencies, and if the decision to build is made, a new plant would not be online until the middle of the next decade.
 
PEC’s jurisdictions also have laws regarding nuclear baseload generation. South Carolina law includes provisions for cost-recovery mechanisms associated with nuclear baseload generation. North Carolina law authorizes the NCUC to allow annual prudence reviews of baseload generating plant construction costs and inclusion of construction work in progress in rate base with corresponding rate adjustment in a general rate case while a baseload generating plant is under construction.
 
SECURITY
 
The NRC issues orders with regard to security at nuclear plants in response to new or emerging threats. The most recent 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 are working to complete the requirements as outlined in the orders by November 30, 2011. 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 (as amended) 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.
 
Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. We have contracts with the DOE for the future storage and disposal of our spent nuclear fuel. Delays have occurred in the DOE’s proposed permanent repository to be located at Yucca Mountain, Nev. See Note 22C for information about the complaint filed by the Utilities in the United States Court of Federal Claims against the DOE for its failure to fulfill its contractual obligation to receive spent fuel from nuclear plants. Failure to open the Yucca Mountain or another facility would leave the DOE open to further claims by utilities.
 
Until the DOE begins to accept the spent nuclear fuel, the Utilities will continue to safely manage their spent nuclear fuel. 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 by their respective systems through the expiration of the operating licenses, including any license renewals, for their nuclear generating units. Harris has sufficient storage capacity in its spent fuel pools through the expiration of its renewed operating license.
 
 
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DECOMMISSIONING
 
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 4C for a discussion of the Utilities’ nuclear decommissioning costs.
 
ENVIRONMENTAL
 
GENERAL
 
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 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.”
 
The foundation for Progress Energy’s environmental leadership strategy begins with its environmental management system.  Under the environmental management system, the Environmental, Health and Safety Performance Council, which is comprised of senior executives, 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. 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.
 
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 statutes. 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 several sites with respect to which we have been notified of our potential liability by the EPA, the state of North Carolina, the state of Florida or potentially responsible parties (PRP) groups. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. 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 plan to submit claims for cost recovery where appropriate. The outcome of potential and pending 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. Hazardous and solid waste management matters are discussed in detail in Note 21A.
 
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.”
 
 
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Growing state, federal and international attention to global climate change may result in the regulation of carbon dioxide (CO2) and other GHGs. The EPA has announced a schedule for development of a new source performance standard for new and existing fossil fuel-fired electric utility units. Under the schedule, the EPA will propose the standard by July 2011 and issue the final rule by May 2012. The full impact of regulation under GHG initiatives and final legislation, if enacted, 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 generate electricity through our balanced solution strategy of EE, alternative energy and a state-of-the-art power system as discussed in MD&A – “Other Matters – Energy Demand.” We continuously evaluate new generation options to determine if they are cost effective 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.
 
EMPLOYEES
 
At February 22, 2011, 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 (IBEW). The three-year labor contract with the IBEW expires in December 2011. Contract negotiations are expected to begin in the fall of 2011. We cannot predict the outcome of the contract negotiations. 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 22, 2011, PEC and PEF employed approximately 5,500 and 4,000 full-time employees, respectively.
 
SEASONALITY AND THE IMPACT OF WEATHER
 
Seasonal differences in the weather affect demand for electricity. The Utilities experience higher demand during the summer and winter months.  As a result, our overall operating results may fluctuate substantially on a seasonal basis.
 
Beyond the impact of seasonality, deviations from normal weather conditions can significantly affect our financial performance. Our residential and commercial customers are most impacted by weather.  Industrial customers are less weather sensitive. We define normal weather conditions as the long-term average of actual historical weather conditions. The number of years used to calculate normal weather is determined by management and differs by jurisdiction.
 
We estimate the impact of weather on our earnings based on the number of customers, temperature variances from a normal condition and the amount of electricity the average residential, commercial and some governmental customers historically demonstrated to use per degree day. Our methodology used to estimate the impact of weather does not and cannot consider all variables that may impact customer response to weather conditions such as humidity and relative temperature changes. The precision of this estimate may also be impacted by applying long-term weather trends to shorter term periods.
 
Degree-day data are used to estimate the energy required to maintain comfortable indoor temperatures based on each day’s average temperature. Heating-degree days measure the variation in the weather based on the extent to which the average daily temperature falls below a base temperature and cooling-degree days measure the variation in weather based on the extent to which the average daily temperature rises above the base temperature. Each degree of temperature below the base temperature counts as one heating-degree day and each degree of temperature above the base temperature counts as one cooling-degree day. PEC’s base temperature for heating- and cooling-degree days is
 
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65° Fahrenheit for all customer classes. PEF’s base temperatures vary by customer class, ranging from 65° to 70° Fahrenheit for cooling-degree days and 55° to 65° Fahrenheit for heating-degree days.
 
 
19

 
 
PEC
 
GENERAL
 
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, 2010, PEC had a total summer generating capacity (including jointly owned capacity) of 12,554 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, 2010, 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. Major industries in PEC’s service area include chemicals, textiles, paper, food, metals, wood products, rubber and plastics and stone products. No single customer accounts for more than 10 percent of PEC’s revenues.
 
PEC’s net income available to parent was $600 million, $513 million and $531 million for the years ended December 31, 2010, 2009 and 2008, respectively. PEC’s total assets were $14.899 billion and $13.502 billion at December 31, 2010 and 2009, respectively.
 
 
REVENUES
 
See “Electric Utility Regulated Operating Statistics – PEC” for information about energy sales and operating revenues.
 
 
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.
 
See “Electric Utility Regulated Operating Statistics – PEC” for generated and purchased energy supply by source and PEC’s average fuel cost.
 
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:
 
 
 
2010
   
2009
   
2008
 
Coal
    47 %     44 %     45 %
Nuclear
    38 %     44 %     43 %
Oil/Gas
    8 %     6 %     4 %
Purchased Power
    6 %     5 %     7 %
Hydro
    1 %     1 %     1 %
 
PEC is generally permitted to pass the cost of fuel and certain purchased power costs to its customers through fuel cost-recovery clauses. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income. 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,
 
 
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“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.
 
Coal
 
PEC anticipates a burn requirement of approximately 11.2 million tons of coal in 2011. Approximately 90 percent of the coal is expected to be supplied from Central Appalachian, 5 percent from Northern Appalachian, and 5 percent from Illinois Basin coal sources and will be primarily delivered by rail.
 
For 2011, 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 Note 7B, PEC has announced that it intends to retire certain coal-fired units representing approximately 30 percent of its coal-fired power generation fleet no later than the end of 2014 as part of a major coal-to-gas modernization strategy. See “Oil and Gas” for planned gas facilities.
 
Nuclear
 
Nuclear fuel is processed through four distinct stages: uranium ore mining and milling, conversion, enrichment, and fabrication. PEC has sufficient contracts for each stage 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
 
The NCUC has granted PEC permission to construct three new generating facilities: an approximately 600-MW combined cycle dual-fuel facility at its Richmond County, N.C., generating facility, an approximately 950-MW combined cycle natural gas-fueled facility at a site in Wayne County, N.C., and an approximately 620-MW natural gas-fueled generating facility at its Sutton coal plant site in New Hanover County, N.C. The facilities are expected to be placed in service in June 2011, January 2013 and December 2013, respectively.
 
Oil and natural gas supply for PEC’s generation fleet is purchased under term and spot contracts from various suppliers. PEC uses derivative instruments to limit its exposure to price fluctuations for natural gas. 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 and intrastate pipelines. PEC may also purchase additional shorter-term transportation for its load requirements during peak periods.
 
Purchased Power
 
PEC purchased approximately 4.0 million MWh, 3.3 million MWh and 4.7 million MWh of its system energy requirements during 2010, 2009 and 2008, respectively, under purchase obligations and operating leases and had 1,332 MW of firm purchased capacity under contract during 2010. 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.
 
Hydroelectric
 
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 its Tillery and Blewett Plants for 50 years and anticipates a decision by the FERC in 2011. The Walters Plant license will expire in 2034.

 
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PEF
 
GENERAL
 
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, 2010, PEF had a total summer generating capacity (including jointly owned capacity) of 10,025 MW. For additional information about PEF’s generating plants, 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, 2010, PEF was providing electric services, retail and wholesale, to approximately 1.6 million customers. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., the city of Gainesville, Reedy Creek Improvement District, Florida Municipal Power Agency and the city of Winter Park. 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. No single customer accounts for more than 10 percent of PEF’s revenues.
 
PEF’s net income available to parent was $451 million, $460 million and $383 million for the years ended December 31, 2010, 2009 and 2008, respectively. PEF’s total assets were $14.056 billion and $13.100 billion at December 31, 2010 and 2009, respectively.
 
REVENUES
 
See “Electric Utility Regulated Operating Statistics – PEF” for information about energy sales and operating revenues.
 
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.
 
See “Electric Utility Regulated Operating Statistics – PEF” for PEF’s energy supply by source and energy fuel cost.
 
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:
 
 
 
 
2010
   
2009
   
2008
 
Oil/Gas
    54  %      44   %     34  %
Coal
    26  %      25  %     30  %
Purchased Power
    20  %      20  %     21  %
 Nuclear(a)
    %      11  %      15  %
 
(a)
Due to the extended outage at CR3 nuclear generating unit that began in September 2009, no nuclear power was generated in 2010.
 
 
PEF is generally permitted to pass the cost of fuel and certain purchased power to its customers through fuel cost-recovery clauses. Because these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income. 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
 
 
22

 
 
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.
 
Oil and Gas
 
Oil and natural gas supply for PEF’s generation fleet is purchased under term and spot contracts from various suppliers. PEF uses derivative instruments to limit its exposure to price fluctuations for natural gas and oil. 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 may also purchase additional shorter-term transportation for its load requirements during peak periods.
 
Coal
 
PEF anticipates a burn requirement of approximately 4.5 million tons of coal in 2011. Approximately 75 percent of the coal is expected to be supplied from the Illinois Basin, 20 percent from Central Appalachian and 5 percent from Northern Appalachian coal sources. Approximately 20 percent of the coal is expected to be delivered by rail and the remainder by water.
 
For 2011, PEF has intermediate and long-term contracts from various sources for approximately 90 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.
 
Purchased Power
 
PEF purchased approximately 9.5 million MWh, 8.7 million MWh and 10.2 million MWh of its system energy requirements during 2010, 2009 and 2008, respectively, under purchase obligations, operating leases and capital leases and had 3,275 MW of firm purchased capacity under contract during 2010. 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
 
Nuclear fuel is processed through four distinct stages: uranium ore mining and milling, conversion, enrichment, and fabrication. PEF has sufficient contracts for each stage 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.”

 
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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 $195 million, $216 million and $84 million for the years ended December 31, 2010, 2009 and 2008, respectively. Corporate and Other segment total assets were $21.110 billion and $20.538 billion at December 31, 2010 and 2009, respectively, which were primarily comprised of the Parent’s investments in subsidiaries.
 

 
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ELECTRIC UTILITY REGULATED OPERATING STATISTICS – PROGRESS ENERGY
 
   
Years Ended December 31
 
 
 
2010
   
2009
   
2008
   
2007
   
2006
 
 Energy supply (millions of kWH)
 
 
   
 
   
 
   
 
   
 
 
Generated
 
 
   
 
   
 
   
 
   
 
 
Steam
    44,971       40,420       46,771       51,163       48,770  
Nuclear
    21,624       29,412       30,565       30,336       30,602  
Combustion turbines/combined cycle
    27,856       21,254       15,557       13,319       11,857  
Hydro
    608       651       429       415       594  
Purchased
    13,473       11,996       14,956       14,994       14,664  
Total energy supply (company share)(a)
    108,532       103,733       108,278       110,227       106,487  
Jointly owned share(a) (b)
    5,228       5,500       5,780       5,351       5,224  
Total system energy supply
    113,760       109,233       114,058       115,578       111,711  
 Average fuel costs (per million Btu)
                                       
Oil
  $ 13.15     $ 11.78     $ 9.60     $ 8.70     $ 7.14  
Gas
  $ 6.92     $ 8.36     $ 10.14     $ 8.67     $ 7.90  
Coal
  $ 3.70     $ 3.85     $ 3.50     $ 3.06     $ 2.99  
Nuclear
  $ 0.59     $ 0.53     $ 0.46     $ 0.45     $ 0.44  
Weighted-average
  $ 3.90     $ 3.79     $ 3.66     $ 3.17     $ 2.86  
 Energy sales (millions of kWH)
                                       
Retail
                                       
Residential
    39,632       36,516       36,328       37,112       36,280  
Commercial
    26,080       25,523       26,080       26,215       25,333  
Industrial
    13,884       13,653       15,174       15,721       16,553  
Other retail
    4,860       4,753       4,768       4,805       4,695  
Unbilled
    630       491       (107 )     (61 )     (272 )
Wholesale
    17,856       17,801       21,063       21,333       19,018  
Total energy sales
    102,942       98,737       103,306       105,125       101,607  
Company uses and losses
    5,590       4,996       4,972       5,102       4,880  
Total energy requirements
    108,532       103,733       108,278       110,227       106,487  
 Operating revenues (in millions)
                                       
Retail
                                       
Billed
  $ 8,714     $ 8,449     $ 7,585     $ 7,672     $ 7,429  
Unbilled
    28       14       7       1       (6 )
Wholesale
    1,080       1,114       1,288       1,191       1,039  
Miscellaneous revenue
    354       301       280       270       263  
Total operating revenues of the Utilities
  $ 10,176     $ 9,878     $ 9,160     $ 9,134     $ 8,725  
 
(a)
The extended outage at PEF's CR3 nuclear generating unit that began in September 2009 impacted the energy supply mix in 2010 and 2009.
(b)
Amounts represent joint owners' share of the energy supplied from the six generating facilities that are jointly owned.

 
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ELECTRIC UTILITY REGULATED OPERATING STATISTICS – PEC
 
   
Years Ended December 31
 
 
 
2010
   
2009
   
2008
   
2007
   
2006
 
 Energy supply (millions of kWH)
 
 
   
 
   
 
   
 
   
 
 
Generated
 
 
   
 
   
 
   
 
   
 
 
Steam
    30,528       27,261       28,363       30,770       28,985  
Nuclear
    21,624       24,467       24,140       24,212       24,220  
Combustion turbines/combined cycle
    5,429       3,634       2,795       2,960       2,106  
Hydro
    608       651       429       415       594  
Purchased
    3,985       3,251       4,735       3,901       4,229  
Total energy supply (company share)
    62,174       59,264       60,462       62,258       60,134  
Jointly owned share(a)
    5,228       5,057       5,205       4,800       4,649  
Total system energy supply
    67,402       64,321       65,667       67,058       64,783  
 Average fuel costs (per million Btu)
                                       
Oil
  $ 14.34     $ 14.84     $ 16.05     $ 12.28     $ 11.04  
Gas
  $ 6.59     $ 8.17     $ 10.66     $ 9.19     $ 9.87  
Coal
  $ 3.56     $ 3.82     $ 3.39     $ 2.96     $ 2.90  
Nuclear
  $ 0.59     $ 0.53     $ 0.46     $ 0.44     $ 0.43  
Weighted-average
  $ 2.69     $ 2.60     $ 2.44     $ 2.21     $ 2.06  
 Energy sales (millions of kWH)
                                       
Retail
                                       
Residential
    19,108       17,117       17,000       17,200       16,259  
Commercial
    14,184       13,639       13,941       14,032       13,358  
Industrial
    10,665       10,368       11,388       11,901       12,393  
Other retail
    1,574       1,497       1,466       1,438       1,419  
Unbilled
    172       360       (8 )     (55 )     (137 )
Wholesale
    13,999       13,966       14,329       15,309       14,584  
Total energy sales
    59,702       56,947       58,116       59,825       57,876  
Company uses and losses
    2,472       2,317       2,346       2,433       2,258  
Total energy requirements
    62,174       59,264       60,462       62,258       60,134  
 Operating revenues (in millions)
                                       
Retail
                                       
Billed
  $ 4,044     $ 3,801     $ 3,582     $ 3,534     $ 3,268  
Unbilled
    11       5       8       -       (1 )
Wholesale
    729       707       737       754       720  
Miscellaneous revenue
    138       114       102       97       99  
Total operating revenues
  $ 4,922     $ 4,627     $ 4,429     $ 4,385     $ 4,086  
 
(a)
Amounts represent joint owners' share of the energy supplied from the four generating facilities that are jointly owned.

 
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ELECTRIC UTILITY REGULATED OPERATING STATISTICS – PEF
 
   
Years Ended December 31
 
 
 
2010
   
2009
   
2008
   
2007
 
2006
 
 Energy supply (millions of kWH)
 
 
   
 
   
 
   
 
   
 
 
Generated
 
 
   
 
   
 
   
 
   
 
 
Steam
    14,443       13,159       18,408       20,393       19,785  
Nuclear
    -       4,945       6,425       6,124       6,382  
Combustion turbines/combined cycle
    22,427       17,620       12,762       10,359       9,751  
Purchased
    9,488       8,745       10,221       11,093       10,435  
Total energy supply (company share)(a)
    46,358       44,469       47,816       47,969       46,353  
Jointly owned share(a) (b)
    -       443       575       551       575  
Total system energy supply
    46,358       44,912       48,391       48,520       46,928  
 Average fuel costs (per million Btu)
                                       
Oil
  $ 12.96     $ 11.43     $ 9.24     $ 8.54     $ 7.03  
Gas
  $ 7.00     $ 8.40     $ 10.03     $ 8.51     $ 7.41  
Coal
  $ 4.09     $ 4.25     $ 3.74     $ 3.28     $ 3.16  
Nuclear
  $ -     $ 0.52     $ 0.49     $ 0.48     $ 0.50  
Weighted-average
  $ 6.14     $ 5.88     $ 5.67     $ 4.85     $ 4.21  
 Energy sales (millions of kWH)
                                       
Retail
                                       
Residential
    20,524       19,399       19,328       19,912       20,021  
Commercial
    11,896       11,884       12,139       12,183       11,975  
Industrial
    3,219       3,285       3,786       3,820       4,160  
Other retail
    3,286       3,256       3,302       3,367       3,276  
Unbilled
    458       131       (99 )     (6 )     (135 )
Wholesale
    3,857       3,835       6,734       6,024       4,434  
Total energy sales
    43,240       41,790       45,190       45,300       43,731  
Company uses and losses
    3,118       2,679       2,626       2,669       2,622  
Total energy requirements
    46,358       44,469       47,816       47,969       46,353  
 Operating revenues (in millions)
                                       
Retail
                                       
Billed
  $ 4,670     $ 4,648     $ 4,003     $ 4,138     $ 4,161  
Unbilled
    17       9       (1 )     1       (5 )
Wholesale
    351       407       551       437       319  
Miscellaneous revenue
    216       187       178       173       164  
Total operating revenues
  $ 5,254     $ 5,251     $ 4,731     $ 4,749     $ 4,639  
 
(a)
The extended outage at PEF's CR3 nuclear generating unit that began in September 2009 impacted the energy supply mix in 2010 and 2009.
(b)
Amounts represent joint owners' share of the energy supplied from the two generating facilities that are jointly owned. Replacement power was supplied to the CR3 joint owners in 2010 from other generation sources or purchased power.

 
27

 

ITEM 1A.                      RISK FACTORS
 
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 may be unable to obtain the approvals required to complete our merger with Duke Energy or, obtaining required governmental and regulatory approvals may require the combined company to comply with restrictions or conditions that may materially impact the anticipated benefits of the Merger.
 
On January 10, 2011, we announced the execution of a definitive merger agreement with Duke Energy. Before the Merger may be completed, shareholder approval must be obtained by both companies. In addition, various filings must be made with the NCUC, the SCPSC, the Kentucky Public Service Commission, the FERC, the NRC and various utility regulatory, antitrust and other regulatory authorities in the United States. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following consummation that may materially impact the anticipated benefits of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, which could have a material adverse effect on the financial results of the combined company and/or cause either party to abandon the Merger.
 
We are also subject to the risk that a required condition to the Merger may not be satisfied. Both companies are targeting to complete the Merger in 2011 but are subject to uncertainties related to the timing needed to consummate the Merger.
 
In the event that the Merger Agreement is terminated prior to the completion of the Merger, we could incur significant transaction costs that could materially impact our financial performance and results. Failure to complete the Merger could also negatively impact our stock price and our future business and financial results.

We will incur significant merger transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the Merger. If the Merger is not completed, depending upon the reasons for not completing the Merger, including whether we have received or entered into a competing takeover proposal, we may be required to pay Duke Energy a termination fee of $400 million. The occurrence of either of these events individually or in combination could have a material adverse affect on our financial results.
 
If completed, our merger with Duke Energy may not achieve the anticipated results and benefits.
 
We and Duke Energy entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies primarily relating to the regulated businesses. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether our businesses and the businesses of Duke Energy can be integrated in an efficient, effective and timely manner. As noted above, as a result of obtaining all necessary regulatory approvals, certain restrictions or conditions may be imposed on the combined company that materially impact or limit the benefits anticipated by us as a result of the Merger. The combined company is also subject to the risk that the expected cost savings and operational synergies may not be fully realized. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected liquidity provided by the combined company and diversion of management's time and energy and could have an adverse effect on the combined company's business, financial results and prospects.
 
 
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We will be subject to business uncertainties and contractual restrictions while the merger with Duke Energy is pending that could adversely affect our financial results.
 
Uncertainty about the effect of the Merger on employees or suppliers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause suppliers and others that deal with us to seek to change existing business relationships.
 
Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our business operations and financial results could be adversely affected.
 
Merger- and integration-related issues will place a significant burden on management and internal resources. The diversion of management time on merger-related issues could affect our financial results.
 
In addition, the Merger Agreement restricts us, without Duke Energy's consent, from making certain acquisitions and taking other specified actions, including limiting our total capital spending, limiting the extent to which we can obtain financing through long-term debt and equity issuances or increasing the Parent’s common stock dividend rate until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to consummation of the Merger or termination of the Merger Agreement. Unless the Merger Agreement is terminated earlier, we and Duke Energy will each have the right to terminate the Merger Agreement if the Merger has not been completed by January 8, 2012 (which date is subject to extension under certain circumstances).
 
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, particularly if the costs of those changes are not fully recoverable from our ratepayers.
 
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 through cost-recovery clauses of certain additional costs, known as “pass-through” costs, 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
 
 
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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:
 
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operator error and breakdown or failure of equipment or processes, including repair and replacement power costs;
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failure of information technology systems and network infrastructure;
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operational limitations imposed by environmental or other regulatory requirements;
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limitations imposed on our nuclear generating units by regulatory agencies or a failure to obtain required licenses for our nuclear generating units, as discussed later;
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inadequate or unreliable access to transmission and distribution assets;
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labor disputes and inability to recruit and retain skilled technical workers;
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inability to successfully and timely execute repair, maintenance and/or refueling outages;
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interruptions to the supply of fuel and other commodities used in generation;
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failure to comply with FERC-mandated reliability standards for the bulk power electric system;
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inadequate coal combustion product management (disposal or beneficial use) capabilities;
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failure to adequately forecast system requirements and commodity requirements; and
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catastrophic events such as hurricanes, floods, extreme drought, earthquakes, fires, explosions, terrorist attacks, pandemic health events or other similar occurrences.
 
Occurrences of these events could adversely affect our financial condition or results of operations.
 
A significant portion of our generating facilities was constructed many years ago. Aging equipment, even if maintained in accordance with industry practices, may require significant capital expenditures. Failure of equipment or facilities could potentially increase O&M expense, purchased power expenses and capital expenditures.
 
Meeting the anticipated demand in our service territories and fulfilling our environmental compliance strategies will require, among other things, modernization of coal generating facilities, the construction of new generating 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 power systems 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.
 
 
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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 capacity 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. We intend to retire certain coal-fired units in North Carolina that do not have emission control equipment by the end of 2014 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:
 
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projected system load growth;
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performance of existing generation fleet;
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availability of competitively priced alternative energy sources;
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projections of fuel prices, availability and security;
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the regulatory environment, including the ability to recover costs and earn an appropriate return on investment;
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operational performance of new technologies;
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the time required to permit and construct;
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environmental impact;
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both public and policymaker support, including support for siting of power plant and associated transmission;
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siting and construction of transmission facilities;
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cost and availability of construction equipment, materials and skilled labor;
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nuclear decommissioning costs, insurance, and costs of security;
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ability to obtain financing on favorable terms; and
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availability of adequate water supply.
 
There is no assurance that we will be able to successfully and timely construct new generating 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 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
 
 
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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 generating 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.
 
Nuclear
 
In addition to the risks discussed above, the successful construction of a new nuclear power plant requires the satisfaction of a number of conditions. The conditions include, but are not limited to, the continued operation of the industry’s existing nuclear fleet in a safe, reliable and cost-effective manner, an efficient and successful licensing process and a viable program for managing spent nuclear fuel. We cannot provide certainty that these conditions will exist. While we have not made a final determination on nuclear construction, we have taken steps to keep open the option of building a plant or plants. We will continue to evaluate the ongoing viability of our nuclear construction projects based on certain criteria, including obtaining the COL; public, regulatory and political support; adequate financial cost-recovery mechanisms; and availability and terms of capital financing. Adverse changes in these criteria could result in project cost increases or project termination.
 
PEF has entered into an EPC agreement for Levy. However, because of schedule shifts, we executed an amendment to the EPC agreement and will postpone major construction activities on the project until after the NRC issues the COL. Because we have executed an amendment to the EPC agreement and anticipate negotiating additional amendments upon receipt of the COL, we cannot currently predict the timing of when those obligations will be satisfied or the magnitude of any change. In light of the schedule shifts, PEF may incur disposition fees and charges related to the disposition of outstanding purchase orders on long lead time equipment for the Levy nuclear project, which could be material. In June 2010, PEF completed its long lead time equipment disposition analysis to minimize the impact associated with the schedule shift. PEF is in suspension negotiations with the equipment vendors regarding those long lead time equipment items for which work was suspended. The amount of disposition fees and charges, if any, cannot be determined until suspension negotiations are completed.
 
In addition, other COL applicants would be pursuing regulatory approval, permitting and construction at roughly the same time as we would. Consequently, there may be shortages of qualified individuals to design, construct and operate these proposed new nuclear facilities.
 
Gas
 
In addition to the risks discussed above, the successful construction of a gas-fired plant requires access to an adequate supply of natural gas. The gas pipeline infrastructure in eastern and western North Carolina is limited. Existing pipelines will have to be extended to the new plant locations prior to commencement of operations, which introduces the risks associated with a critical construction project not under our direct control. Power plants fueled by fossil fuels such as natural gas and fuel oil emit GHG, which may be subject to future regulation.
 
Coal
 
In addition to the risks discussed above, the successful modernization of a coal-fired power plant requires the satisfaction of a number of conditions, including, but not limited to, consideration of emissions that impact air and water quality and management of coal combustion products such as slag, bottom ash and fly ash.
 
 
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We are subject to renewable energy standards that may have a negative impact on our business, financial condition and results of operations.
 
We are subject to state renewable energy standards in North Carolina. North Carolina’s standards include use of energy from specified renewable energy resources or implementation of energy-efficiency measures totaling 12.5 percent by 2021. Florida energy law enacted in 2008 includes provisions for development of a renewable portfolio standard but the rulemaking process is not complete. We may be subject to additional state or federal level standards in the future that could require the Utilities to produce or buy a higher portion of their energy from renewable energy sources. Mandated state and federal standards could result in the use of renewable energy sources that are not cost-effective in order to comply with requirements. If we are not able to receive retail rates reflecting our costs or investments to comply with the state or federal standards, our financial condition and results of operation may be adversely affected.
 
There are inherent potential risks in the operation of nuclear facilities, including environmental, health, safety, regulatory, terrorism, and financial risks, that could result in fines or the shutdown of our nuclear units, which may present potential financial exposures in excess of our insurance coverage.
 
PEC operates four nuclear units (three of which are jointly owned) and PEF jointly owns and operates one nuclear unit. In addition, we are exploring the possibility of expanding our nuclear generating capacity to meet future expected baseload generation needs. Our nuclear facilities are subject to operational, environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, maintaining adequate capital reserves for decommissioning, limitations on amounts and types of insurance available, potential operational liabilities and extended outages, and the costs of securing the facilities against possible terrorist attacks. We maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, damages from an accident or business interruption at our nuclear units could exceed the amount of our insurance coverage. For PEF, it may incur liabilities to co-owners in the event of extended outages or operation at less than full capacity. If the Utilities are not allowed to recover the additional costs incurred either through insurance or regulatory mechanisms, our results of operations could be negatively impacted.
 
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. 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. Revised safety requirements promulgated by the NRC could require us to make substantial expenditures at our nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
 
Our nuclear facilities have operating licenses that need to be renewed periodically. We anticipate successful renewal of these licenses. However, potential terrorist threats and increased public scrutiny of utilities could result in an extended process with higher licensing or compliance costs.
 
With construction beginning on a number of new nuclear facilities around the world, and the prospect of several projects across the United States, there will be increased competition within the energy sector for skilled technical workers for both the construction and operation of nuclear facilities. Our ability to successfully operate our nuclear facilities is dependent upon our continued ability to recruit and retain skilled technical workers.
 
We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and may impact or limit our business plans, or expose us to environmental liabilities.
 
We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste production, handling and disposal. These laws and regulations can result in increased capital, operating and other costs, particularly with regard to enforcement efforts focused on existing power plants and compliance plans with regard to new and existing power plants. These laws and regulations generally require us to obtain and comply with a wide
 
 
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variety of environmental licenses, permits, authorizations and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. Failure to comply with applicable regulations and permits might result in the imposition of fines and penalties by regulatory authorities. We cannot provide assurance that existing environmental regulations will not be revised or that new environmental regulations will not be adopted or become applicable to us. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a material adverse effect on our results of operations, particularly if those costs are not fully recoverable from our ratepayers.
 
In addition, we may be deemed a responsible party for environmental clean-up at sites identified by a regulatory body or private party. We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs. While we accrue for probable costs that can be reasonably estimated, 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.
 
Our coal-fired plants produce coal combustion products, primarily ash. The EPA and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or additional environmental controls for groundwater protection, and future mitigation of related impacts could have a material impact on our results of operations or financial condition. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures.
 
Our compliance with evolving environmental regulations, including those regarding water quality and the reduction of emissions of NOx, SO2 and mercury from coal-fired power plants, is anticipated to require significant capital expenditures that could impact our financial condition. These costs are anticipated to be eligible for regulatory recovery through either base rates or cost-recovery clauses.
 
The operation of emission control equipment needed to comply with requirements set by various environmental regulations increases our operating costs and reduces the generating capacity of our coal-fired plants. O&M expenses significantly increase due to the additional personnel, materials and general maintenance associated with operation of the equipment. Operation of the emission control equipment requires the procurement of significant quantities of reagents, such as limestone and ammonia. Future increases in demand for these items from other utility companies operating similar equipment could increase our costs associated with operating the equipment. Additionally, the operation of emission control equipment may result in the development of collateral issues that require further remedial actions, resulting in additional expenditures and operating costs.
 
We are subject to risks associated with climate change, which could have a negative impact on our business, financial condition and results of operations. Future legislation or regulations related to climate change may impose significant restrictions on CO2 and other GHG emissions. We may incur significant costs to comply with such legislation or regulations or in connection with related litigation. Physical risks associated with climate change could impact us.
 
Growing state, federal and international attention to global climate change may result in the regulation of CO2 and other GHGs. Any future legislative or regulatory actions taken to address global climate change represent a business risk to our operations and the full impact of such initiatives on our operations cannot be determined at this time; however, we anticipate that it could result in significant cost increases over time, for which the Utilities would seek corresponding rate recovery. Reductions in CO2 emissions to the levels specified by some proposals could be materially adverse to our financial position or results of operations if associated costs of control or limitation cannot be recovered from ratepayers.
 
According to the Intergovernmental Panel on Climate Change, potential climate change impacts in the southeastern United States could include warmer days and nights, increased total rainfall from heavy storms, increased severe weather events, sea level rise and increased drought conditions. An increase in the number of heat waves, periods of
 
 
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drought and sea level rise could result in changes in energy demand due to shifting populations and industry. As noted below, severe weather may adversely affect our results of operations.
 
We could become subject to litigation related to the purported impacts of GHG emissions. A number of legal actions have been filed against other electric utilities asserting public and private nuisance, trespass and negligence claims.
 
Because weather conditions directly influence the demand for, our ability to provide, and the cost of providing electricity, our results of operations, financial condition and cash flows can fluctuate on a seasonal or quarterly basis and can be negatively affected by changes in weather conditions and severe weather.
 
Weather conditions in our service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to our customers. As a result, our future overall operating results may fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions were mild. Unusually mild weather could diminish our results of operations and harm our financial condition.
 
Sustained severe drought conditions could impact generation by PEC’s hydroelectric plants, as well as our fossil and nuclear plant operations, as these facilities use water for cooling purposes and for the operation of environmental compliance equipment. Furthermore, destruction caused by severe weather events, such as hurricanes, tornadoes, severe thunderstorms, snow and ice storms, can result in lost operating revenues due to outages; property damage, including downed transmission and distribution lines; and additional and unexpected expenses to mitigate storm damage.
 
Our ability to recover significant costs resulting from severe weather events is subject to regulatory oversight, and the timing and amount of any such recovery is uncertain and may impact our financial conditions.
 
We are subject to incurring significant costs resulting from damage sustained during severe weather events. While the Utilities have historically been granted regulatory approval to defer and amortize or collect from customers the majority of significant storm costs incurred, the Utilities’ storm cost-recovery petitions may not always be granted or may not be granted in a timely manner. If we cannot recover costs associated with future severe weather events in a timely manner, or in an amount sufficient to cover our actual costs, our financial conditions and results of operations could be materially and adversely impacted.
 
Under its base rate settlement agreement, PEF is allowed to recover the costs of named storms on an expedited basis through a surcharge on monthly residential customer bills for storm costs. In the event the storm costs exceed the maximum allowed surcharge, excess additional costs can be deferred and recovered in a subsequent year or years as determined by the FPSC. Additionally, the order approving the settlement agreement allows PEF to use the surcharge to replenish the storm damage reserve to a specified level after storm costs are fully recovered.
 
PEC does not maintain a storm damage reserve account and does not have a cost-recovery clause to recover storm costs. PEC may request recovery of significant storm-related costs; PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over agreed-upon time periods.
 
Our revenues, operating results and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions. We are also impacted by the demand and competitive state of the wholesale market.
 
Our revenues, operating results and financial condition are impacted by customer growth and usage. Customer growth can be impacted by population growth as well as by economic factors, including but not limited to, job growth and housing market trends. The Utilities are impacted by the economic cycles of the customers we serve. As our service territories experience economic downturns, residential customer consumption patterns may change and our revenues may be negatively impacted. If our commercial and industrial customers experience economic downturns, their consumption of electricity may decline and our revenues can be negatively impacted. Like other parts of the United States, our service territories and business have been impacted by the current economic conditions. The timing and extent of the recovery of the economy cannot be predicted. Additionally, our customers
 
 
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could voluntarily reduce their consumption of electricity in response to decreases in their disposable income or individual energy conservation efforts.
 
Wholesale revenues fluctuate with regional demand, fuel prices and contracted capacity. Our wholesale profitability is dependent upon market conditions and our ability to renew or replace expiring wholesale contracts on favorable terms. Based on economic conditions in effect when wholesale contracts expire, the Utilities may not be successful in renewing or replacing expiring contracts.
 
Fluctuations in commodity prices or availability may adversely affect various aspects of the Utilities’ operations as well as the Utilities’ financial condition, results of operations or cash flows.
 
We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, nuclear fuel, electricity and other energy-related commodities, including emission allowances, as a result of our ownership of energy-related assets. Fuel costs are recovered primarily through cost-recovery clauses, subject to the Utilities’ state utility commissions’ approval. Additionally, we have hedging strategies in place to mitigate fluctuations in commodity supply prices, but to the extent that we do not cover our entire exposure to commodity price fluctuations, or our hedging procedures do not work as planned, there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. Additionally, we are exposed to risk that our counterparties will not be able to perform their obligations. Should our counterparties fail to perform, we might be forced to replace the underlying commitment at prevailing market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.
 
Certain of our hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. Downgrades in our credit ratings could lead to additional collateral posting requirements. We continually monitor our derivative positions in relation to market price activity.
 
Volatility in market prices for fuel and power may result from, among other items:
 
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weather conditions;
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seasonality;
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power usage;
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illiquid markets;
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transmission or transportation constraints or inefficiencies;
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technological changes;
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availability of competitively priced alternative energy sources;
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demand for energy commodities;
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natural gas, crude oil and refined products, nuclear fuel and coal production levels;
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natural disasters, wars, terrorism, embargoes and other catastrophic events; and
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federal, state and foreign energy and environmental regulation and legislation.
 
In addition, we anticipate significant capital expenditures for environmental compliance and baseload generation. The completion of these projects within established budgets is contingent upon many variables including the securing of labor and materials at estimated costs. The demand and prices for labor and materials are subject to volatility and may increase in the future. We are subject to the risk that cost overages may not be recoverable from ratepayers and our financial condition, results of operations or cash flows may be adversely impacted.
 
Prices for emission allowance credits fluctuate. While allowances are eligible for annual recovery in PEF’s jurisdictions in Florida and PEC’s in South Carolina, no such annual recovery exists in North Carolina for PEC. Future changes in the price of allowances could have a significant adverse financial impact on us and PEC and, consequently, on our results of operations and cash flows.
 
 
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As a holding company with no revenue-generating operations, the Parent is dependent on upstream cash flows from its subsidiaries, primarily the Utilities; its commercial paper and credit facilities; and its ability to access the long-term debt and equity capital markets.
 
The Parent is a holding company and, as such, has no revenue-generating operations of its own. The primary cash needs at the Parent level are our common stock dividend, interest and principal payments on the Parent’s senior unsecured debt and potentially funding a portion of the Utilities’ capital expenditures through equity contributions. The Parent’s ability to meet these needs is typically funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; repayment of funds due to the Parent by its subsidiaries; the Parent’s credit facility; and/or the Parent’s ability to access the short-term and long-term debt and equity capital markets.
 
Prior to funding the Parent, its subsidiaries have financial obligations that must be satisfied, including, among others, their respective debt service, preferred dividends and obligations to trade creditors. Additionally, the Utilities could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from the Parent. Should the Utilities not be able to pay dividends or repay funds due to the Parent or if the Parent cannot access the commercial paper market, its credit facilities or the long-term debt and equity capital markets, the Parent’s ability to pay principal, interest and dividends would be restricted. The Parent could change its existing common stock dividend policy based upon these and other business factors
 
Our business is dependent on our ability to successfully access capital markets on favorable terms. Limits on our access to capital may adversely impact our ability to execute our business plan or pursue improvements that we would otherwise rely on for future growth.
 
Our cash requirements are driven by the capital-intensive nature of our Utilities. In addition to operating cash flows, we rely heavily on commercial paper, long-term debt and equity issuances. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy will be adversely affected. Market disruptions or a downgrade of our credit ratings could increase our cost of borrowing and may adversely affect our ability to access the financial markets. If we cannot fund our expected capital expenditures and debt maturities through normal operations or by accessing capital markets, our business plans, financial condition, results of operations or cash flows may be adversely impacted.
 
We typically issue commercial paper to meet short-term liquidity needs. When financial and economic conditions result in tightened short-term credit markets, coupled with corresponding volatility in commercial paper durations and interest rates, we evaluate other options for meeting our short-term liquidity needs, which may include borrowing from our revolving credit agreements (RCAs), issuing short-term notes, issuing long-term debt and/or issuing equity. In addition, if our short-term credit ratings are downgraded below Tier 2 (A-2/P-2/F2) we could experience increased volatility in commercial paper durations and interest rates and our access to the commercial paper markets may be negatively impacted. In that case, we would evaluate other options for meeting our short-term liquidity needs as previously described. These alternative sources of liquidity may not be available or may not have comparable favorable terms and, thus, may impact adversely our business plans, financial condition, and results of operations or cash flows.
 
Increases in our leverage or reductions in our cash flow could adversely affect our competitive position, business planning and flexibility, financial condition, ability to service our debt obligations and to pay dividends on our common stock, and ability to access capital on favorable terms.
 
As discussed above, we typically rely heavily on our commercial paper and long-term debt. Our credit agreements contain certain provisions and impose various limitations that could impact our liquidity, such as cross-default provisions and defined maximum total debt to total capital (leverage) ratios. Under these revolving credit facilities, indebtedness includes certain letters of credit and guarantees that are not recorded on the Consolidated Balance Sheets.
 
As previously discussed, we are anticipating extensive capital needs for new generation, transmission and distribution facilities, and environmental compliance expenditures. Funding these capital needs could increase our leverage and present numerous risks including those addressed below.
 
 
37

 
 
In the event our leverage increases such that we approach the permitted ratios, our access to capital and additional liquidity could decrease. A limitation in our liquidity could have a material adverse impact on our business strategy and our ongoing financing needs. Additionally, a significant increase in our leverage or reductions in cash flow could adversely affect us by:
 
§  
increasing the cost of future debt financing;
§  
impacting our ability to pay dividends on our common stock at the current rate;
§  
making it more difficult for us to satisfy our existing financial obligations;
§  
increasing our vulnerability to adverse economic and industry conditions;
§  
requiring us to dedicate a substantial portion of our cash flow from operations to debt repayment, thereby reducing funds available for operations, future business opportunities or other purposes;
§  
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete;
§  
requiring the issuance of additional equity;
§  
placing us at a competitive disadvantage compared to competitors who have less debt; and
§  
causing a downgrade in our credit ratings.
 
Any reduction in our credit ratings below investment grade would likely increase our financing costs, limit our access to additional capital and require posting of collateral, all of which could materially and adversely affect our business, results of operations and financial condition.
 
While the long-term target credit ratings for the Parent and the Utilities are above the minimum investment grade rating, we cannot provide certainty that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Such circumstances could include, among others, increases in leverage, adverse changes in other financial metrics, and adverse regulatory outcomes. Our debt indentures and credit agreements do not contain any “ratings triggers,” which would cause the acceleration of interest and principal payments in the event of a ratings downgrade. Any downgrade could increase our borrowing costs, may adversely affect our access to capital and could result in the posting of additional collateral for derivatives in a liability position, which could negatively impact our financial results and business plans. Any reduction in our credit ratings below investment grade could also result in collateral posting requirements for certain of our natural gas transportation contracts. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities or those of PEC or PEF and that each agency’s rating should be evaluated independently of any other agency’s rating.
 
Market performance and other changes may decrease the value of nuclear decommissioning trust funds and benefit plan assets, which then could require significant additional funding.
 
The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations to decommission the Utilities’ nuclear plants and under our defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. Although a number of factors impact our funding requirements, a decline in the market value of the assets may increase the funding requirements of the obligations for decommissioning the Utilities’ nuclear plants and under our defined benefit pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, the funding requirements of the obligations related to these benefit plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or changes in life expectancy assumptions. If we are unable to successfully manage the nuclear decommissioning trust funds and benefit plan assets, our results of operation and financial position could be negatively affected.
 
Impairment of goodwill could have a significant negative impact on our financial condition and results of operations.
 
Goodwill is required to be tested for impairment at least annually and more frequently when indicators of impairment exist. All of our goodwill is allocated to our utility reporting units, and goodwill impairment tests are performed at the utility reporting unit level.
 
 
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We calculate the fair value of our utility reporting units by considering various factors, including valuation studies based primarily on income and market approaches. The calculations in both approaches are highly dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates from a marketplace participant’s perspective, and the selection of peer utilities and marketplace transactions for comparative valuation purposes. The estimated future cash flows are based on the Utilities’ business plans that assume the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, the timing of anticipated significant future capital investments, the anticipated earnings and returns related to such capital investments, continued recovery of cost of service and renewal of certain contracts. These underlying assumptions and estimates are made as of a point in time. If these assumptions change or should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, the fair value of the utility reporting units could be significantly different in future periods, which could result in a future impairment charge to goodwill. Impairment of our recorded goodwill could result in volatility in our earnings under accounting principles generally accepted in the United States of America (GAAP) and an increase in our leverage, which could trigger a downgrade of our credit ratings leading to higher borrowing costs and/or dilution through additional issuances of common stock. However, in the event of a goodwill impairment, we do not expect any such impairment to cause us to violate any financial or restrictive covenants contained in our indebtedness or other contractual arrangements.
 
Our ability to fully utilize tax credits generated under Section 29/45K may be limited. This risk is not applicable to PEC and PEF.
 
In accordance with the provisions of Section 29/45K, we have generated tax credits based on the content and quantity of coal-based solid synthetic fuels produced and sold to unrelated parties. This tax credit program expired at the end of 2007. The timing of the utilization of the tax credits is dependent upon our taxable income, which can be impacted by a number of factors. The timing of the utilization can also be impacted by certain substantial changes in ownership, including the Merger. Additionally, in the normal course of business, our tax returns are audited by the IRS. If our tax credits were disallowed in whole or in part as a result of an IRS audit, there could be significant additional tax liabilities and associated interest for previously recognized tax credits, which could have a material adverse impact on our earnings and cash flows. Although we are unaware of any currently proposed legislation or new IRS regulations or interpretations impacting previously recorded synthetic fuels tax credits, the value of credits generated could be unfavorably impacted by such legislation or IRS regulations and interpretations.
 
UNRESOLVED STAFF COMMENTS
 
None
 

 
39

 

PROPERTIES
 
We believe that our physical properties and those of our subsidiaries are adequate to carry on our and their businesses as currently conducted. We maintain property insurance against loss or damage by fire or other perils to the extent that such property is usually insured.
 
ELECTRIC - PEC
 
PEC’s 18 generating plants represent a flexible mix of fossil steam, nuclear, combustion turbines, combined cycle, and hydroelectric resources, with a total summer generating capacity of 12,554 MW. Of this total, Power Agency owns approximately 700 MW. On December 31, 2010, PEC had the following generating facilities:
 
 
 
 
 
   
 
 
 
 
PEC
   
Summer Net
 
 
 
 
No. of
   
 
 
 
 
Ownership
   
Capability(a)
 
 Facility
Location
 
Units
   
In-Service Date
 
Fuel
 
(in %)
   
(in MW)
 
 FOSSIL STEAM
 
 
 
   
 
 
 
           
 Asheville
Arden, N.C.
    2       1964-1971  
Coal
    100       376  
 Cape Fear(b)
Moncure, N.C.
    2       1956-1958  
Coal
    100       316  
 Lee(b)
Goldsboro, N.C.
    3       1951-1962  
Coal
    100       391  
 Mayo
Roxboro, N.C.
    1       1983  
Coal
    83.83       727 (c)
 Robinson
Hartsville, S.C.
    1       1960  
Coal
    100       177  
 Roxboro
Semora, N.C.
    4       1966-1980  
Coal
    96.3 (d)     2,417 (c)
 Sutton(b)
Wilmington, N.C.
    3       1954-1972  
Coal
    100       590  
 Weatherspoon(b)
Lumberton, N.C.
    3       1949-1952  
Coal
    100       170  
 
Total
    19          
 
            5,164  
 NUCLEAR
 
               
 
               
 Brunswick
Southport, N.C.
    2       1975-1977  
Uranium
    81.67       1,858 (c)
 Harris
New Hill, N.C.
    1       1987  
Uranium
    83.83       900 (c)
 Robinson
Hartsville, S.C.
    1       1971  
Uranium
    100       724  
 
Total
    4          
 
            3,482  
 COMBUSTION TURBINES
               
 
               
 Asheville
Arden, N.C.
    2       1999-2000  
Gas/Oil
    100       324  
 Blewett
Lilesville, N.C.
    4       1971  
Oil
    100       52  
 Darlington
Hartsville, S.C.
    13       1974-1997  
Gas/Oil
    100       802  
 Lee
Goldsboro, N.C.
    4       1968-1971  
Oil
    100       75  
 Morehead City
Morehead City, N.C.
    1       1968  
Oil
    100       12  
 Richmond
Hamlet, N.C.
    5       2001-2002  
Gas/Oil
    100       820  
 Robinson
Hartsville, S.C.
    1       1968  
Gas/Oil
    100       11  
 Sutton
Wilmington, N.C.
    3       1968-1969  
Gas/Oil
    100       61  
 Wayne County
Goldsboro, N.C.
    5       2000-2009  
Gas/Oil
    100       863  
 Weatherspoon
Lumberton, N.C.
    4       1970-1971  
Gas/Oil
    100       131  
 
Total
    42          
 
            3,151  
 COMBINED CYCLE
               
 
               
 Cape Fear
Moncure, N.C.
    2       1969  
Oil
    100       62  
 Richmond
Hamlet, N.C.
    1       2002  
Gas/Oil
    100       470  
 
Total
    3          
 
            532  
 HYDRO
 
               
 
               
 Blewett
Lilesville, N.C.
    6       1912  
Water
    100       22  
 Marshall
Marshall, N.C.
    2       1910  
Water
    100       4  
 Tillery
Mount Gilead, N.C.
    4       1928-1960  
Water
    100       87  
 Walters
Waterville, N.C.
    3       1930  
Water
    100       112  
 
Total
    15          
 
            225  
TOTAL
 
    83          
 
            12,554  
 
(a)
Summer ratings reflect compliance with NERC reliability standards and are gross of joint ownership interest.
(b)
PEC has announced that it intends to retire these units no later than the end of 2014. See Item I, "Business - PEC - Fuel and Purchased Power - Oil and Gas" regarding PEC's plans to build new generation fueled by natural gas.
(c)
Facilities are jointly owned by PEC and Power Agency. The capacities shown include Power Agency's share.
(d)
PEC and Power Agency are joint owners of Unit 4 at the Roxboro Plant. PEC's ownership interest in this 698-MW unit is 87.06 percent.
 
 
40

 
 
At December 31, 2010, including both the total generating capacity of 12,554 MW and the total firm contracts for purchased power of 1,332 MW, PEC had total capacity resources of approximately 13,886 MW.
 
Power Agency has undivided ownership interests of 18.33 percent in Brunswick Unit Nos. 1 and 2, 12.94 percent in Roxboro Unit No. 4, 3.77 percent in Roxboro Common facilities, and 16.17 percent in Harris and Mayo Unit No. 1. Otherwise, PEC has good and marketable title to its principal plants and units, subject to the lien of its mortgage and deed of trust, with minor exceptions, restrictions, and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. PEC also owns certain easements over private property on which transmission and distribution lines are located.
 
At December 31, 2010, PEC had approximately 6,000 circuit miles of transmission lines including 300 miles of 500 kilovolt (kV) lines and 3,000 miles of 230-kV lines. PEC also had approximately 45,000 circuit miles of overhead distribution conductor and 22,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 52 million kilovolt-ampere (kVA) in approximately 900 transformers. Distribution line transformers numbered approximately 538,000 with an aggregate capacity of approximately 24 million kVA.

 
41

 
 
ELECTRIC - PEF
 
PEF’s 14 generating plants represent a flexible mix of fossil steam, combustion turbines, combined cycle, and nuclear resources, with a total summer generating capacity of 10,025 MW. Of this total, joint owners own approximately 120 MW. On December 31, 2010, PEF had the following generating facilities:
 
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PEF
   
Summer Net
 
 
 
 
No. of
   
 
 
 
 
Ownership
   
Capability(a)
 
 Facility
Location
 
Units
   
In-Service Date
 
Fuel
 
(in %)
   
(in MW)
 
 FOSSIL STEAM
 
 
 
   
 
 
 
           
 Anclote
Holiday, Fla.
    2       1974-1978  
Gas/Oil
    100       1,011  
 Crystal River
Crystal River, Fla.
    4       1966-1984  
Coal
    100       2,291  
 Suwannee River
Live Oak, Fla.
    3       1953-1956  
Gas/Oil
    100       131  
 
Total
    9          
 
            3,433  
 COMBINED CYCLE
               
 
               
 Bartow
St. Petersburg, Fla.
    1       2009  
Gas/Oil
    100       1,133  
 Hines
Bartow, Fla.
    4       1999-2007  
Gas/Oil
    100       1,912  
 Tiger Bay
Fort Meade, Fla.
    1       1997  
Gas
    100