Commission File Number
|
Exact name of registrants as specified in their charters, states of incorporation, addresses of principal executive offices,
and telephone numbers
|
I.R.S. Employer Identification Number
|
![]() |
||
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
|
Progress Energy, Inc. (Progress Energy)
|
Yes
|
x
|
No
|
o
|
Carolina Power & Light Company (PEC)
|
Yes
|
x
|
No
|
o
|
Florida Power Corporation (PEF)
|
Yes
|
o
|
No
|
x
|
Progress Energy
|
Yes
|
x
|
No
|
o
|
PEC
|
Yes
|
x
|
No
|
o
|
PEF
|
Yes
|
x
|
No
|
o
|
Progress Energy
|
Large accelerated filer
|
x
|
Accelerated filer
|
o
|
Non-accelerated filer
|
o
|
Smaller reporting company
|
o
|
|
PEC
|
Large accelerated filer
|
o
|
Accelerated filer
|
o
|
Non-accelerated filer
|
x
|
Smaller reporting company
|
o
|
|
PEF
|
Large accelerated filer
|
o
|
Accelerated filer
|
o
|
Non-accelerated filer
|
x
|
Smaller reporting company
|
o
|
Progress Energy
|
Yes
|
o
|
No
|
x
|
PEC
|
Yes
|
o
|
No
|
x
|
PEF
|
Yes
|
o
|
No
|
x
|
Registrant
|
Description
|
Shares
|
Progress Energy
|
Common Stock (Without Par Value)
|
295,005,362
|
PEC
|
Common Stock (Without Par Value)
|
159,608,055 (all of which were held directly by Progress Energy, Inc.)
|
PEF
|
Common Stock (Without Par Value)
|
100 (all of which were held indirectly by Progress Energy, Inc.)
|
TABLE OF CONTENTS
|
||
2
|
||
5
|
||
PART I. FINANCIAL INFORMATION
|
||
ITEM 1.
|
7
|
|
Unaudited Condensed Interim Financial Statements
|
||
Progress Energy, Inc. (Progress Energy)
|
||
7
|
||
8
|
||
9
|
||
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
|
||
10
|
||
11
|
||
12
|
||
Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
|
||
13
|
||
14
|
||
15
|
||
16
|
||
ITEM 2.
|
72
|
|
ITEM 3.
|
110
|
|
ITEM 4.
|
113
|
|
PART II. OTHER INFORMATION
|
||
ITEM 1.
|
114
|
|
ITEM 1A.
|
114
|
|
ITEM 2.
|
115
|
|
ITEM 6.
|
116
|
|
118
|
TERM
|
DEFINITION
|
2010 Form 10-K
|
Progress Registrants’ annual report on Form 10-K for the fiscal year ended December 31, 2010
|
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, PESC 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
|
CSAPR
|
Cross-State Air Pollution Rule
|
CVO
|
Contingent value obligation
|
D.C. Court of Appeals
|
U.S. Court of Appeals for the District of Columbia Circuit
|
DOE
|
U.S. Department of Energy
|
DOJ
|
U.S. Department of Justice
|
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
|
EGU MACT
|
MACT standards for coal-fired and oil-fired electric steam generating units
|
EIP
|
Equity Incentive Plan
|
EPA
|
U.S. Environmental Protection Agency
|
EPC
|
Engineering, procurement and construction
|
ESOP
|
Employee Stock Ownership Plan
|
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 Levy Units No. 1 and No. 2 Nuclear Plants
|
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 I, Item 2 of this Form 10-Q
|
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
|
NO2
|
Nitrogen dioxide
|
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 less 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
|
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
|
the Registration Statement
|
The registration statement filed on Form S-4 by Duke Energy related to the Merger
|
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 I, Item 1 of this Form 10-Q
|
SERC
|
SERC Reliability Corporation
|
S&P
|
Standard & Poor’s Rating Services
|
SO2
|
Sulfur dioxide
|
SOx
|
Sulfur oxides
|
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
|
VSP
|
Voluntary severance plan
|
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
|
·
|
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 scope of necessary repairs of the delamination of PEF’s Crystal River Unit No. 3 Nuclear Plant (CR3) could prove more extensive than is currently identified, such repairs could prove not to be feasible, the costs of repair and/or replacement power could exceed our estimates and insurance coverage or may not be recoverable through the regulatory process;
|
·
|
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, cyber security threats and other catastrophic events;
|
·
|
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);
|
·
|
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 (the 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.
|
ITEM 1. | FINANCIAL STATEMENTS |
PROGRESS ENERGY, INC.
|
||||||||||||||||
UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
|
||||||||||||||||
September 30, 2011
|
||||||||||||||||
|
|
|
|
|
||||||||||||
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
|
||||||||||||||||
|
Three months ended September 30
|
Nine months ended September 30
|
||||||||||||||
(in millions except per share data)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Operating revenues
|
$ | 2,747 | $ | 2,962 | $ | 7,170 | $ | 7,869 | ||||||||
Operating expenses
|
||||||||||||||||
Fuel used in electric generation
|
844 | 935 | 2,236 | 2,574 | ||||||||||||
Purchased power
|
349 | 418 | 898 | 996 | ||||||||||||
Operation and maintenance
|
487 | 474 | 1,491 | 1,459 | ||||||||||||
Depreciation, amortization and accretion
|
175 | 201 | 508 | 680 | ||||||||||||
Taxes other than on income
|
163 | 161 | 437 | 448 | ||||||||||||
Other
|
39 | 20 | 31 | 25 | ||||||||||||
Total operating expenses
|
2,057 | 2,209 | 5,601 | 6,182 | ||||||||||||
Operating income
|
690 | 753 | 1,569 | 1,687 | ||||||||||||
Other income (expense)
|
||||||||||||||||
Interest income
|
1 | 3 | 2 | 6 | ||||||||||||
Allowance for equity funds used during construction
|
22 | 22 | 77 | 68 | ||||||||||||
Other, net
|
(70 | ) | (5 | ) | (60 | ) | (5 | ) | ||||||||
Total other (expense) income, net
|
(47 | ) | 20 | 19 | 69 | |||||||||||
Interest charges
|
||||||||||||||||
Interest charges
|
180 | 197 | 568 | 587 | ||||||||||||
Allowance for borrowed funds used during construction
|
(8 | ) | (8 | ) | (26 | ) | (24 | ) | ||||||||
Total interest charges, net
|
172 | 189 | 542 | 563 | ||||||||||||
Income from continuing operations before income tax
|
471 | 584 | 1,046 | 1,193 | ||||||||||||
Income tax expense
|
178 | 219 | 386 | 456 | ||||||||||||
Income from continuing operations before cumulative effect
of change in accounting principle
|
293 | 365 | 660 | 737 | ||||||||||||
Discontinued operations, net of tax
|
- | (2 | ) | (4 | ) | (2 | ) | |||||||||
Cumulative effect of change in accounting principle, net of tax
|
- | 2 | - | - | ||||||||||||
Net income
|
293 | 365 | 656 | 735 | ||||||||||||
Net income attributable to noncontrolling interests, net of tax
|
(2 | ) | (4 | ) | (5 | ) | (4 | ) | ||||||||
Net income attributable to controlling interests
|
$ | 291 | $ | 361 | $ | 651 | $ | 731 | ||||||||
Average common shares outstanding – basic
|
296 | 294 | 296 | 289 | ||||||||||||
Basic and diluted earnings per common share
|
||||||||||||||||
Income from continuing operations attributable to controlling
interests, net of tax
|
$ | 0.98 | $ | 1.23 | $ | 2.22 | $ | 2.53 | ||||||||
Discontinued operations attributable to controlling interests,
net of tax
|
- | - | (0.02 | ) | - | |||||||||||
Net income attributable to controlling interests
|
$ | 0.98 | $ | 1.23 | $ | 2.20 | $ | 2.53 | ||||||||
Dividends declared per common share
|
$ | 0.620 | $ | 0.620 | $ | 1.860 | $ | 1.860 | ||||||||
Amounts attributable to controlling interests
|
||||||||||||||||
Income from continuing operations, net of tax
|
$ | 291 | $ | 363 | $ | 655 | $ | 733 | ||||||||
Discontinued operations, net of tax
|
- | (2 | ) | (4 | ) | (2 | ) | |||||||||
Net income attributable to controlling interests
|
$ | 291 | $ | 361 | $ | 651 | $ | 731 | ||||||||
|
||||||||||||||||
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
|
PROGRESS ENERGY, INC.
|
||||||||
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
|
||||||||
(in millions)
|
September 30, 2011
|
December 31, 2010
|
||||||
ASSETS
|
|
|
||||||
Utility plant
|
|
|
||||||
Utility plant in service
|
$ | 30,729 | $ | 29,708 | ||||
Accumulated depreciation
|
(11,905 | ) | (11,567 | ) | ||||
Utility plant in service, net
|
18,824 | 18,141 | ||||||
Other utility plant, net
|
222 | 220 | ||||||
Construction work in progress
|
2,233 | 2,205 | ||||||
Nuclear fuel, net of amortization
|
736 | 674 | ||||||
Total utility plant, net
|
22,015 | 21,240 | ||||||
Current assets
|
||||||||
Cash and cash equivalents
|
103 | 611 | ||||||
Receivables, net
|
1,207 | 1,033 | ||||||
Inventory
|
1,376 | 1,226 | ||||||
Regulatory assets
|
180 | 176 | ||||||
Derivative collateral posted
|
112 | 164 | ||||||
Deferred tax assets
|
285 | 156 | ||||||
Prepayments and other current assets
|
162 | 110 | ||||||
Total current assets
|
3,425 | 3,476 | ||||||
Deferred debits and other assets
|
||||||||
Regulatory assets
|
2,333 | 2,374 | ||||||
Nuclear decommissioning trust funds
|
1,512 | 1,571 | ||||||
Miscellaneous other property and investments
|
410 | 413 | ||||||
Goodwill
|
3,655 | 3,655 | ||||||
Other assets and deferred debits
|
327 | 325 | ||||||
Total deferred debits and other assets
|
8,237 | 8,338 | ||||||
Total assets
|
$ | 33,677 | $ | 33,054 | ||||
CAPITALIZATION AND LIABILITIES
|
||||||||
Common stock equity
|
||||||||
Common stock without par value, 500 million shares authorized, 295
million and 293 million shares issued and outstanding, respectively
|
$ | 7,414 | $ | 7,343 | ||||
Accumulated other comprehensive loss
|
(207 | ) | (125 | ) | ||||
Retained earnings
|
2,905 | 2,805 | ||||||
Total common stock equity
|
10,112 | 10,023 | ||||||
Noncontrolling interests
|
3 | 4 | ||||||
Total equity
|
10,115 | 10,027 | ||||||
Preferred stock of subsidiaries
|
93 | 93 | ||||||
Long-term debt, affiliate
|
273 | 273 | ||||||
Long-term debt, net
|
11,717 | 11,864 | ||||||
Total capitalization
|
22,198 | 22,257 | ||||||
Current liabilities
|
||||||||
Current portion of long-term debt
|
950 | 505 | ||||||
Short-term debt
|
45 | - | ||||||
Accounts payable
|
895 | 994 | ||||||
Interest accrued
|
184 | 216 | ||||||
Dividends declared
|
185 | 184 | ||||||
Customer deposits
|
339 | 324 | ||||||
Derivative liabilities
|
303 | 259 | ||||||
Accrued compensation and other benefits
|
140 | 175 | ||||||
Other current liabilities
|
507 | 298 | ||||||
Total current liabilities
|
3,548 | 2,955 | ||||||
Deferred credits and other liabilities
|
||||||||
Noncurrent income tax liabilities
|
2,310 | 1,696 | ||||||
Accumulated deferred investment tax credits
|
104 | 110 | ||||||
Regulatory liabilities
|
2,326 | 2,635 | ||||||
Asset retirement obligations
|
1,253 | 1,200 | ||||||
Accrued pension and other benefits
|
1,226 | 1,514 | ||||||
Derivative liabilities
|
255 | 278 | ||||||
Other liabilities and deferred credits
|
457 | 409 | ||||||
Total deferred credits and other liabilities
|
7,931 | 7,842 | ||||||
Commitments and contingencies (Notes 14 and 15)
|
||||||||
Total capitalization and liabilities
|
$ | 33,677 | $ | 33,054 | ||||
|
|
|||||||
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
|
PROGRESS ENERGY, INC.
|
||||||||
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
|
||||||||
(in millions)
|
|
|
||||||
Nine months ended September 30
|
2011
|
2010
|
||||||
Operating activities
|
|
|
||||||
Net income
|
$ | 656 | $ | 735 | ||||
Adjustments to reconcile net income to net cash provided by operating activities
|
||||||||
Depreciation, amortization and accretion
|
632 | 804 | ||||||
Deferred income taxes and investment tax credits, net
|
430 | 263 | ||||||
Deferred fuel credit
|
(11 | ) | (37 | ) | ||||
Allowance for equity funds used during construction
|
(77 | ) | (68 | ) | ||||
Other adjustments to net income
|
202 | 197 | ||||||
Cash (used) provided by changes in operating assets and liabilities
|
||||||||
Receivables
|
(93 | ) | (252 | ) | ||||
Inventory
|
(152 | ) | 111 | |||||
Derivative collateral posted
|
52 | (83 | ) | |||||
Other assets
|
(19 | ) | (25 | ) | ||||
Income taxes, net
|
20 | 213 | ||||||
Accounts payable
|
(40 | ) | 45 | |||||
Accrued pension and other benefits
|
(359 | ) | (162 | ) | ||||
Other liabilities
|
63 | 163 | ||||||
Net cash provided by operating activities
|
1,304 | 1,904 | ||||||
Investing activities
|
||||||||
Gross property additions
|
(1,535 | ) | (1,643 | ) | ||||
Nuclear fuel additions
|
(134 | ) | (164 | ) | ||||
Purchases of available-for-sale securities and other investments
|
(4,536 | ) | (5,927 | ) | ||||
Proceeds from available-for-sale securities and other investments
|
4,509 | 5,915 | ||||||
Insurance proceeds
|
78 | 18 | ||||||
Other investing activities
|
43 | (3 | ) | |||||
Net cash used by investing activities
|
(1,575 | ) | (1,804 | ) | ||||
Financing activities
|
||||||||
Issuance of common stock, net
|
42 | 419 | ||||||
Dividends paid on common stock
|
(550 | ) | (535 | ) | ||||
Net increase (decrease) in short-term debt
|
45 | (140 | ) | |||||
Proceeds from issuance of long-term debt, net
|
1,286 | 591 | ||||||
Retirement of long-term debt
|
(1,000 | ) | (400 | ) | ||||
Other financing activities
|
(60 | ) | (69 | ) | ||||
Net cash used by financing activities
|
(237 | ) | (134 | ) | ||||
Net decrease in cash and cash equivalents
|
(508 | ) | (34 | ) | ||||
Cash and cash equivalents at beginning of period
|
611 | 725 | ||||||
Cash and cash equivalents at end of period
|
$ | 103 | $ | 691 | ||||
Supplemental disclosures
|
||||||||
Significant noncash transactions
|
||||||||
Accrued property additions
|
$ | 253 | $ | 255 | ||||
|
||||||||
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
|
CAROLINA POWER & LIGHT COMPANY
|
||||||||||||||||
d/b/a PROGRESS ENERGY CAROLINAS, INC.
|
||||||||||||||||
UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
|
||||||||||||||||
September 30, 2011
|
||||||||||||||||
|
|
|
|
|
||||||||||||
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of INCOME
|
||||||||||||||||
|
Three months ended September 30
|
Nine months ended September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Operating revenues
|
$ | 1,332 | $ | 1,414 | $ | 3,525 | $ | 3,794 | ||||||||
Operating expenses
|
||||||||||||||||
Fuel used in electric generation
|
388 | 464 | 1,077 | 1,322 | ||||||||||||
Purchased power
|
117 | 109 | 257 | 235 | ||||||||||||
Operation and maintenance
|
271 | 256 | 859 | 841 | ||||||||||||
Depreciation, amortization and accretion
|
132 | 120 | 382 | 358 | ||||||||||||
Taxes other than on income
|
57 | 58 | 163 | 169 | ||||||||||||
Other
|
38 | 5 | 38 | 5 | ||||||||||||
Total operating expenses
|
1,003 | 1,012 | 2,776 | 2,930 | ||||||||||||
Operating income
|
329 | 402 | 749 | 864 | ||||||||||||
Other income (expense)
|
||||||||||||||||
Interest income
|
- | 1 | 1 | 3 | ||||||||||||
Allowance for equity funds used during construction
|
15 | 17 | 53 | 45 | ||||||||||||
Other, net
|
(4 | ) | (2 | ) | (5 | ) | (5 | ) | ||||||||
Total other income, net
|
11 | 16 | 49 | 43 | ||||||||||||
Interest charges
|
||||||||||||||||
Interest charges
|
45 | 51 | 149 | 154 | ||||||||||||
Allowance for borrowed funds used during construction
|
(4 | ) | (5 | ) | (15 | ) | (14 | ) | ||||||||
Total interest charges, net
|
41 | 46 | 134 | 140 | ||||||||||||
Income before income tax
|
299 | 372 | 664 | 767 | ||||||||||||
Income tax expense
|
100 | 138 | 227 | 284 | ||||||||||||
Income before cumulative effect of change in accounting principle
|
199 | 234 | 437 | 483 | ||||||||||||
Cumulative effect of change in accounting principle, net of tax
|
- | 2 | - | - | ||||||||||||
Net income
|
199 | 236 | 437 | 483 | ||||||||||||
Net (income) loss attributable to noncontrolling interests, net of tax
|
- | (2 | ) | - | 1 | |||||||||||
Net income attributable to controlling interests
|
199 | 234 | 437 | 484 | ||||||||||||
Preferred stock dividend requirement
|
(1 | ) | (1 | ) | (2 | ) | (2 | ) | ||||||||
Net income available to parent
|
$ | 198 | $ | 233 | $ | 435 | $ | 482 | ||||||||
|
||||||||||||||||
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
|
CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
|
||||||||
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
|
||||||||
(in millions)
|
September 30, 2011
|
December 31, 2010
|
||||||
ASSETS
|
|
|
||||||
Utility plant
|
|
|
||||||
Utility plant in service
|
$ | 17,234 | $ | 16,388 | ||||
Accumulated depreciation
|
(7,505 | ) | (7,324 | ) | ||||
Utility plant in service, net
|
9,729 | 9,064 | ||||||
Other utility plant, net
|
186 | 184 | ||||||
Construction work in progress
|
1,141 | 1,233 | ||||||
Nuclear fuel, net of amortization
|
522 | 480 | ||||||
Total utility plant, net
|
11,578 | 10,961 | ||||||
Current assets
|
||||||||
Cash and cash equivalents
|
67 | 230 | ||||||
Receivables, net
|
547 | 519 | ||||||
Receivables from affiliated companies
|
27 | 44 | ||||||
Inventory
|
734 | 590 | ||||||
Deferred fuel cost
|
52 | 71 | ||||||
Income taxes receivable
|
17 | 90 | ||||||
Deferred tax assets
|
112 | 65 | ||||||
Prepayments and other current assets
|
99 | 47 | ||||||
Total current assets
|
1,655 | 1,656 | ||||||
Deferred debits and other assets
|
||||||||
Regulatory assets
|
1,029 | 987 | ||||||
Nuclear decommissioning trust funds
|
992 | 1,017 | ||||||
Miscellaneous other property and investments
|
185 | 183 | ||||||
Other assets and deferred debits
|
104 | 95 | ||||||
Total deferred debits and other assets
|
2,310 | 2,282 | ||||||
Total assets
|
$ | 15,543 | $ | 14,899 | ||||
CAPITALIZATION AND LIABILITIES
|
||||||||
Common stock equity
|
||||||||
Common stock without par value, 200 million shares authorized, 160
million shares issued and outstanding
|
$ | 2,144 | $ | 2,130 | ||||
Accumulated other comprehensive loss
|
(70 | ) | (33 | ) | ||||
Retained earnings
|
3,068 | 3,083 | ||||||
Total common stock equity
|
5,142 | 5,180 | ||||||
Preferred stock
|
59 | 59 | ||||||
Long-term debt, net
|
3,693 | 3,693 | ||||||
Total capitalization
|
8,894 | 8,932 | ||||||
Current liabilities
|
||||||||
Current portion of long-term debt
|
500 | - | ||||||
Accounts payable
|
496 | 534 | ||||||
Payables to affiliated companies
|
88 | 109 | ||||||
Interest accrued
|
65 | 74 | ||||||
Customer deposits
|
114 | 106 | ||||||
Derivative liabilities
|
93 | 53 | ||||||
Accrued compensation and other benefits
|
81 | 99 | ||||||
Other current liabilities
|
147 | 81 | ||||||
Total current liabilities
|
1,584 | 1,056 | ||||||
Deferred credits and other liabilities
|
||||||||
Noncurrent income tax liabilities
|
1,902 | 1,608 | ||||||
Accumulated deferred investment tax credits
|
100 | 104 | ||||||
Regulatory liabilities
|
1,443 | 1,461 | ||||||
Asset retirement obligations
|
889 | 849 | ||||||
Accrued pension and other benefits
|
519 | 723 | ||||||
Other liabilities and deferred credits
|
212 | 166 | ||||||
Total deferred credits and other liabilities
|
5,065 | 4,911 | ||||||
Commitments and contingencies (Notes 14 and 15)
|
||||||||
Total capitalization and liabilities
|
$ | 15,543 | $ | 14,899 | ||||
|
|
|||||||
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
|
CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
|
||||||||
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
|
||||||||
(in millions)
|
|
|
||||||
Nine months ended September 30
|
2011
|
2010
|
||||||
Operating activities
|
|
|
||||||
Net income
|
$ | 437 | $ | 483 | ||||
Adjustments to reconcile net income to net cash provided by operating activities
|
||||||||
Depreciation, amortization and accretion
|
491 | 450 | ||||||
Deferred income taxes and investment tax credits, net
|
222 | 123 | ||||||
Deferred fuel cost
|
19 | 63 | ||||||
Allowance for equity funds used during construction
|
(53 | ) | (45 | ) | ||||
Other adjustments to net income
|
20 | 68 | ||||||
Cash provided (used) by changes in operating assets and liabilities
|
||||||||
Receivables
|
56 | (89 | ) | |||||
Receivables from affiliated companies
|
17 | 15 | ||||||
Inventory
|
(144 | ) | 120 | |||||
Other assets
|
(5 | ) | (41 | ) | ||||
Income taxes, net
|
79 | 59 | ||||||
Accounts payable
|
(41 | ) | (18 | ) | ||||
Payables to affiliated companies
|
(21 | ) | (1 | ) | ||||
Accrued pension and other benefits
|
(228 | ) | (103 | ) | ||||
Other liabilities
|
39 | 65 | ||||||
Net cash provided by operating activities
|
888 | 1,149 | ||||||
Investing activities
|
||||||||
Gross property additions
|
(901 | ) | (867 | ) | ||||
Nuclear fuel additions
|
(121 | ) | (132 | ) | ||||
Purchases of available-for-sale securities and other investments
|
(430 | ) | (352 | ) | ||||
Proceeds from available-for-sale securities and other investments
|
401 | 323 | ||||||
Changes in advances to affiliated companies
|
(59 | ) | 199 | |||||
Other investing activities
|
16 | - | ||||||
Net cash used by investing activities
|
(1,094 | ) | (829 | ) | ||||
Financing activities
|
||||||||
Dividends paid on preferred stock
|
(2 | ) | (2 | ) | ||||
Dividends paid to parent
|
(450 | ) | (75 | ) | ||||
Proceeds from issuance of long-term debt, net
|
496 | - | ||||||
Contributions from parent
|
- | 14 | ||||||
Other financing activities
|
(1 | ) | - | |||||
Net cash provided (used) by financing activities
|
43 | (63 | ) | |||||
Net (decrease) increase in cash and cash equivalents
|
(163 | ) | 257 | |||||
Cash and cash equivalents at beginning of period
|
230 | 35 | ||||||
Cash and cash equivalents at end of period
|
$ | 67 | $ | 292 | ||||
Supplemental disclosures
|
||||||||
Significant noncash transactions
|
||||||||
Accrued property additions
|
$ | 179 | $ | 160 | ||||
|
||||||||
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.
|
FLORIDA POWER CORPORATION
|
||||||||||||||||
d/b/a PROGRESS ENERGY FLORIDA, INC.
|
||||||||||||||||
UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
|
||||||||||||||||
September 30, 2011
|
||||||||||||||||
|
|
|
|
|
||||||||||||
UNAUDITED CONDENSED STATEMENTS of INCOME
|
||||||||||||||||
|
Three months ended September 30
|
Nine months ended September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Operating revenues
|
$ | 1,414 | $ | 1,543 | $ | 3,639 | $ | 4,065 | ||||||||
Operating expenses
|
||||||||||||||||
Fuel used in electric generation
|
456 | 471 | 1,159 | 1,252 | ||||||||||||
Purchased power
|
232 | 309 | 641 | 761 | ||||||||||||
Operation and maintenance
|
221 | 234 | 655 | 647 | ||||||||||||
Depreciation, amortization and accretion
|
39 | 77 | 112 | 311 | ||||||||||||
Taxes other than on income
|
106 | 102 | 274 | 278 | ||||||||||||
Other
|
(1 | ) | 6 | (13 | ) | 6 | ||||||||||
Total operating expenses
|
1,053 | 1,199 | 2,828 | 3,255 | ||||||||||||
Operating income
|
361 | 344 | 811 | 810 | ||||||||||||
Other income (expense)
|
||||||||||||||||
Interest income
|
1 | - | 1 | 1 | ||||||||||||
Allowance for equity funds used during construction
|
7 | 5 | 24 | 23 | ||||||||||||
Other, net
|
(1 | ) | (3 | ) | 3 | - | ||||||||||
Total other income, net
|
7 | 2 | 28 | 24 | ||||||||||||
Interest charges
|
||||||||||||||||
Interest charges
|
50 | 68 | 187 | 202 | ||||||||||||
Allowance for borrowed funds used during construction
|
(4 | ) | (3 | ) | (11 | ) | (10 | ) | ||||||||
Total interest charges, net
|
46 | 65 | 176 | 192 | ||||||||||||
Income before income tax
|
322 | 281 | 663 | 642 | ||||||||||||
Income tax expense
|
119 | 101 | 245 | 241 | ||||||||||||
Net income
|
203 | 180 | 418 | 401 | ||||||||||||
Preferred stock dividend requirement
|
- | - | (1 | ) | (1 | ) | ||||||||||
Net income available to parent
|
$ | 203 | $ | 180 | $ | 417 | $ | 400 | ||||||||
|
||||||||||||||||
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.
|
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
|
||||||||
UNAUDITED CONDENSED BALANCE SHEETS
|
||||||||
(in millions)
|
September 30, 2011
|
December 31, 2010
|
||||||
ASSETS
|
|
|
||||||
Utility plant
|
|
|
||||||
Utility plant in service
|
$ | 13,331 | $ | 13,155 | ||||
Accumulated depreciation
|
(4,322 | ) | (4,168 | ) | ||||
Utility plant in service, net
|
9,009 | 8,987 | ||||||
Held for future use
|
36 | 36 | ||||||
Construction work in progress
|
1,092 | 972 | ||||||
Nuclear fuel, net of amortization
|
214 | 194 | ||||||
Total utility plant, net
|
10,351 | 10,189 | ||||||
Current assets
|
||||||||
Cash and cash equivalents
|
18 | 249 | ||||||
Receivables, net
|
629 | 496 | ||||||
Receivables from affiliated companies
|
21 | 11 | ||||||
Inventory
|
643 | 636 | ||||||
Regulatory assets
|
128 | 105 | ||||||
Derivative collateral posted
|
98 | 140 | ||||||
Deferred tax assets
|
83 | 77 | ||||||
Prepayments and other current assets
|
58 | 29 | ||||||
Total current assets
|
1,678 | 1,743 | ||||||
Deferred debits and other assets
|
||||||||
Regulatory assets
|
1,305 | 1,387 | ||||||
Nuclear decommissioning trust funds
|
520 | 554 | ||||||
Miscellaneous other property and investments
|
43 | 43 | ||||||
Other assets and deferred debits
|
117 | 140 | ||||||
Total deferred debits and other assets
|
1,985 | 2,124 | ||||||
Total assets
|
$ | 14,014 | $ | 14,056 | ||||
CAPITALIZATION AND LIABILITIES
|
||||||||
Common stock equity
|
||||||||
Common stock without par value, 60 million shares authorized,
100 shares issued and outstanding
|
$ | 1,755 | $ | 1,750 | ||||
Accumulated other comprehensive loss
|
(26 | ) | (4 | ) | ||||
Retained earnings
|
3,084 | 3,144 | ||||||
Total common stock equity
|
4,813 | 4,890 | ||||||
Preferred stock
|
34 | 34 | ||||||
Long-term debt, net
|
4,482 | 4,182 | ||||||
Total capitalization
|
9,329 | 9,106 | ||||||
Current liabilities
|
||||||||
Current portion of long-term debt
|
- | 300 | ||||||
Notes payable to affiliated companies
|
69 | 9 | ||||||
Accounts payable
|
377 | 439 | ||||||
Payables to affiliated companies
|
67 | 60 | ||||||
Interest accrued
|
60 | 83 | ||||||
Customer deposits
|
225 | 218 | ||||||
Derivative liabilities
|
175 | 188 | ||||||
Accrued compensation and other benefits
|
34 | 47 | ||||||
Other current liabilities
|
237 | 121 | ||||||
Total current liabilities
|
1,244 | 1,465 | ||||||
Deferred credits and other liabilities
|
||||||||
Noncurrent income tax liabilities
|
1,411 | 1,065 | ||||||
Regulatory liabilities
|
796 | 1,084 | ||||||
Asset retirement obligations
|
364 | 351 | ||||||
Accrued pension and other benefits
|
414 | 522 | ||||||
Capital lease obligations
|
190 | 199 | ||||||
Derivative liabilities
|
168 | 190 | ||||||
Other liabilities and deferred credits
|
98 | 74 | ||||||
Total deferred credits and other liabilities
|
3,441 | 3,485 | ||||||
Commitments and contingencies (Notes 14 and 15)
|
||||||||
Total capitalization and liabilities
|
$ | 14,014 | $ | 14,056 | ||||
|
|
|||||||
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.
|
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
|
||||||||
UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
|
||||||||
(in millions)
|
|
|
||||||
Nine months ended September 30
|
2011
|
2010
|
||||||
Operating activities
|
|
|
||||||
Net income
|
$ | 418 | $ | 401 | ||||
Adjustments to reconcile net income to net cash provided by operating activities
|
||||||||
Depreciation, amortization and accretion
|
113 | 328 | ||||||
Deferred income taxes and investment tax credits, net
|
291 | 211 | ||||||
Deferred fuel credit
|
(30 | ) | (100 | ) | ||||
Allowance for equity funds used during construction
|
(24 | ) | (23 | ) | ||||
Other adjustments to net income
|
70 | 89 | ||||||
Cash (used) provided by changes in operating assets and liabilities
|
||||||||
Receivables
|
(134 | ) | (155 | ) | ||||
Receivables from affiliated companies
|
(10 | ) | (5 | ) | ||||
Inventory
|
(10 | ) | (11 | ) | ||||
Derivative collateral posted
|
43 | (59 | ) | |||||
Other assets
|
(1 | ) | (20 | ) | ||||
Income taxes, net
|
51 | 117 | ||||||
Accounts payable
|
(2 | ) | 70 | |||||
Payables to affiliated companies
|
7 | (18 | ) | |||||
Accrued pension and other benefits
|
(123 | ) | (51 | ) | ||||
Other liabilities
|
61 | 121 | ||||||
Net cash provided by operating activities
|
720 | 895 | ||||||
Investing activities
|
||||||||
Gross property additions
|
(624 | ) | (774 | ) | ||||
Nuclear fuel additions
|
(13 | ) | (32 | ) | ||||
Purchases of available-for-sale securities and other investments
|
(4,097 | ) | (5,456 | ) | ||||
Proceeds from available-for-sale securities and other investments
|
4,098 | 5,460 | ||||||
Insurance proceeds
|
74 | 18 | ||||||
Other investing activities
|
39 | (2 | ) | |||||
Net cash used by investing activities
|
(523 | ) | (786 | ) | ||||
Financing activities
|
||||||||
Dividends paid on preferred stock
|
(1 | ) | (1 | ) | ||||
Dividends paid to parent
|
(475 | ) | (50 | ) | ||||
Proceeds from issuance of long-term debt, net
|
296 | 591 | ||||||
Retirement of long-term debt
|
(300 | ) | (300 | ) | ||||
Changes in advances from affiliated companies
|
60 | (213 | ) | |||||
Other financing activities
|
(8 | ) | (8 | ) | ||||
Net cash (used) provided by financing activities
|
(428 | ) | 19 | |||||
Net (decrease) increase in cash and cash equivalents
|
(231 | ) | 128 | |||||
Cash and cash equivalents at beginning of period
|
249 | 17 | ||||||
Cash and cash equivalents at end of period
|
$ | 18 | $ | 145 | ||||
Supplemental disclosures
|
||||||||
Significant noncash transactions
|
||||||||
Accrued property additions
|
$ | 72 | $ | 92 | ||||
Nuclear repairs insurance recovery
|
48 | 75 | ||||||
|
||||||||
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.
|
Registrant
|
Applicable Notes
|
PEC
|
1 through 9, 11, 12, 14 and 15
|
PEF
|
1 through 9, 11, 12, 14 and 15
|
1. | ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
A. | ORGANIZATION |
B. | BASIS OF PRESENTATION |
|
Three months ended September 30
|
Nine months ended September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Progress Energy
|
$ | 96 | $ | 101 | $ | 245 | $ | 265 | ||||||||
PEC
|
33 | 34 | 86 | 91 | ||||||||||||
PEF
|
63 | 67 | 159 | 174 |
C. | CONSOLIDATION OF VARIABLE INTEREST ENTITIES |
(in millions)
|
September 30, 2011
|
December 31, 2010
|
||||||
Miscellaneous other property and investments
|
$ | 12 | $ | 12 | ||||
Cash and cash equivalents
|
1 | - | ||||||
Prepayments and other current assets
|
- | 1 | ||||||
Accounts payable
|
- | 5 | ||||||
|
2. | MERGER AGREEMENT |
·
|
On August 23, 2011, the Merger was approved by the shareholders of Progress Energy and Duke Energy.
|
·
|
On March 28, 2011, Progress Energy and Duke Energy submitted their Hart-Scott-Rodino filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.
|
·
|
On July 27, 2011, the Federal Communications Commission approved the Assignment of Authorization filings to transfer control of certain licenses. The approval is effective for 180 days.
|
·
|
On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC’s acceptance of market power mitigation measures to address the FERC’s finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina power markets. Progress Energy and Duke Energy filed a market power mitigation plan with FERC on October 17, 2011. In the October 17, 2011 filing with the FERC, Progress Energy and Duke Energy proposed a “virtual divestiture” under which power up to a certain amount will be offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. In the proposal, after native loads have been met, power will be offered to entities serving load in the relevant areas at a price determined by the average incremental cost plus 10 percent. On a day-ahead order confirmation basis, PEC plans to offer 500 megawatt-hours (MWh) during each summer hour, which is less than 4 percent of PEC’s summer net capability. Duke Energy Carolinas plans to offer 300 MWh during each summer hour and 225 MWh during each winter hour. On October 31, 2011, Progress Energy and Duke Energy filed a request for a rehearing of the Merger order without withdrawing the previously submitted market power mitigation plan. In the request for rehearing, Progress Energy and Duke Energy asserted that the FERC had departed from its established merger rules in applying a more stringent analysis to assess whether the Merger will result in market power conditions in the Carolinas. We have requested that the FERC address the mitigation plan no later than December 15, 2011. If the FERC accepts the mitigation proposal, we will withdraw the request for a rehearing.
|
·
|
On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a Joint Dispatch Agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the Merger. The second filing is a joint open access transmission tariff pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate.
|
·
|
On March 30, 2011, Progress Energy and Duke Energy made filings with the NRC for approval for indirect transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses. The period to request a hearing or intervene expired in September 2011, and no such requests were received.
|
·
|
On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed the settlement with the South Carolina Office of Regulatory Staff, a party to the proceedings. If the settlement agreement is approved, Progress Energy and Duke Energy will guarantee $650 million in fuel cost savings for customers in North Carolina and South Carolina between 2012 and 2016, maintain their current level of community support for the next four years, and provide $15 million for low-income energy assistance and workforce development. The parties also agreed that direct merger-related expenses would not be recovered from customers. Recovery of merger-related employee severance costs can be requested separately. The NCUC held hearings regarding these applications on September 20-22, 2011, and proposed orders and/or briefs must be filed by November 14, 2011.
|
·
|
On April 25, 2011, Progress Energy and Duke Energy filed a merger-related filing and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the merger-related filing, as the merger of these entities is not likely to occur for several years after the close of the Merger. Hearings before the SCPSC to approve the Joint Dispatch Agreement have been rescheduled for the week of December 12, 2011. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
|
·
|
On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy’s and Duke Energy’s merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky.
|
3. | NEW ACCOUNTING STANDARDS |
4. | REGULATORY MATTERS |
A. | PEC RETAIL RATE MATTERS |
B. | PEF RETAIL RATE MATTERS |
(in millions)
|
Replacement
Power Costs
|
Repair Costs
|
||||||
Spent to date
|
$ | 457 | $ | 229 | ||||
NEIL proceeds received to date
|
(162 | ) | (136 | ) | ||||
Insurance receivable at September 30, 2011
|
(162 | ) | (48 | ) | ||||
Balance for recovery
|
$ | 133 |
(a)
|
$ | 45 |
(a)
|
|
As approved by the FPSC on January 1, 2011, PEF began collecting, subject to refund, replacement power costs related to CR3 within the fuel clause (See Note 7C in the 2010 Form 10-K). The replacement power costs to be recovered through the fuel clause during 2011 allow for full recovery of all of 2010’s and 2011’s replacement power costs. The 2011 fuel cost-recovery filing, discussed in “Fuel Cost Recovery,” anticipates full recovery of estimated 2012 replacement power costs.
|
5. | EQUITY AND COMPREHENSIVE INCOME |
A. | EARNINGS PER COMMON SHARE |
B. | RECONCILIATION OF TOTAL EQUITY |
(in millions)
|
Total Common
Stock Equity
|
Noncontrolling
Interests
|
Total Equity
|
|||||||||
Balance, December 31, 2010
|
$ | 10,023 | $ | 4 | $ | 10,027 | ||||||
Net income(a)
|
651 | 2 | 653 | |||||||||
Other comprehensive loss
|
(82 | ) | - | (82 | ) | |||||||
Issuance of shares through offerings and stock-
based compensation plans (See Note 5D)
|
70 | - | 70 | |||||||||
Dividends declared
|
(550 | ) | - | (550 | ) | |||||||
Distributions to noncontrolling interests
|
- | (3 | ) | (3 | ) | |||||||
Balance, September 30, 2011
|
$ | 10,112 | $ | 3 | $ | 10,115 | ||||||
Balance, December 31, 2009
|
$ | 9,449 | $ | 6 | $ | 9,455 | ||||||
Cumulative effect of change in accounting
principle
|
- | (2 | ) | (2 | ) | |||||||
Net income(a)
|
731 | 1 | 732 | |||||||||
Other comprehensive loss
|
(77 | ) | - | (77 | ) | |||||||
Issuance of shares through offerings and stock-
based compensation plans (See Note 5D)
|
461 | - | 461 | |||||||||
Dividends declared
|
(543 | ) | - | (543 | ) | |||||||
Distributions to noncontrolling interests
|
- | (2 | ) | (2 | ) | |||||||
Balance, September 30, 2010
|
$ | 10,021 | $ | 3 | $ | 10,024 |
(a)
|
For the nine months ended September 30, 2011, consolidated net income of $656 million includes $3 million attributable to preferred shareholders of subsidiaries. For the nine months ended September 30, 2010, consolidated net income of $735 million includes $3 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.
|
C. | COMPREHENSIVE INCOME |
PROGRESS ENERGY
|
|
|||||||
|
Three months ended September 30
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Net income
|
$ | 293 | $ | 365 | ||||
Other comprehensive income (loss)
|
||||||||
Reclassification adjustments included in net income
|
||||||||
Change in cash flow hedges (net of tax expense of $1 and $1)
|
2 | 1 | ||||||
Change in unrecognized items for pension and other postretirement benefits
(net of tax expense of $1 and $-)
|
2 | 1 | ||||||
Net unrealized losses on cash flow hedges (net of tax benefit of $44 and $19)
|
(69 | ) | (30 | ) | ||||
Net unrecognized items on pension and other postretirement benefits (net of
tax benefit of $2)
|
- | (4 | ) | |||||
Other (net of tax expense of $-)
|
- | (1 | ) | |||||
Other comprehensive loss
|
(65 | ) | (33 | ) | ||||
Comprehensive income
|
228 | 332 | ||||||
Comprehensive income attributable to noncontrolling interests
|
(2 | ) | (4 | ) | ||||
Comprehensive income attributable to controlling interests
|
$ | 226 | $ | 328 | ||||
|
|
|||||||
|
Nine months ended September 30
|
|||||||
(in millions)
|
2011 | 2010 | ||||||
Net income
|
$ | 656 | $ | 735 | ||||
Other comprehensive income (loss)
|
||||||||
Reclassification adjustments included in net income
|
||||||||
Change in cash flow hedges (net of tax expense of $3 and $3)
|
5 | 4 | ||||||
Change in unrecognized items for pension and other postretirement benefits
(net of tax expense of $3 and $1)
|
4 | 3 | ||||||
Net unrealized losses on cash flow hedges (net of tax benefit of $53 and $51)
|
(83 | ) | (80 | ) | ||||
Net unrecognized items on pension and other postretirement benefits (net of
tax benefit of $5 and $2)
|
(8 | ) | (4 | ) | ||||
Other comprehensive loss
|
(82 | ) | (77 | ) | ||||
Comprehensive income
|
574 | 658 | ||||||
Comprehensive income attributable to noncontrolling interests
|
(5 | ) | (4 | ) | ||||
Comprehensive income attributable to controlling interests
|
$ | 569 | $ | 654 |
PEC
|
|
|||||||
|
Three months ended September 30
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Net income
|
$ | 199 | $ | 236 | ||||
Other comprehensive income (loss)
|
||||||||
Reclassification adjustments included in net income
|
||||||||
Change in cash flow hedges (net of tax expense of $1 and $1)
|
1 | 1 | ||||||
Net unrealized losses on cash flow hedges (net of tax benefit of $23 and $7)
|
(35 | ) | (10 | ) | ||||
Other comprehensive loss
|
(34 | ) | (9 | ) | ||||
Comprehensive income
|
165 | 227 | ||||||
Comprehensive income attributable to noncontrolling interests
|
- | (2 | ) | |||||
Comprehensive income attributable to controlling interests
|
$ | 165 | $ | 225 |
|
|
|||||||
|
Nine months ended September 30
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Net income
|
$ | 437 | $ | 483 | ||||
Other comprehensive income (loss)
|
||||||||
Reclassification adjustments included in net income
|
||||||||
Change in cash flow hedges (net of tax expense of $2 and $2)
|
3 | 3 | ||||||
Net unrealized losses on cash flow hedges (net of tax benefit of $26 and $17)
|
(40 | ) | (26 | ) | ||||
Other comprehensive loss
|
(37 | ) | (23 | ) | ||||
Comprehensive income
|
400 | 460 | ||||||
Comprehensive loss attributable to noncontrolling interests
|
- | 1 | ||||||
Comprehensive income attributable to controlling interests
|
$ | 400 | $ | 461 |
PEF
|
|
|||||||
|
Three months ended September 30
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Net income
|
$ | 203 | $ | 180 | ||||
Other comprehensive loss
|
||||||||
Net unrealized losses on cash flow hedges (net of tax benefit of $11 and $3)
|
(17 | ) | (6 | ) | ||||
Other comprehensive loss
|
(17 | ) | (6 | ) | ||||
Comprehensive income
|
$ | 186 | $ | 174 | ||||
|
|
|||||||
|
Nine months ended September 30
|
|||||||
(in millions)
|
2011 | 2010 | ||||||
Net income
|
$ | 418 | $ | 401 | ||||
Other comprehensive loss
|
||||||||
Net unrealized losses on cash flow hedges (net of tax benefit of $14 and $10)
|
(22 | ) | (16 | ) | ||||
Other comprehensive loss
|
(22 | ) | (16 | ) | ||||
Comprehensive income
|
$ | 396 | $ | 385 |
D. | COMMON STOCK |
2011
|
2010
|
|||||||||||||||
(in millions)
|
Shares
|
Net
Proceeds
|
Shares
|
Net
Proceeds
|
||||||||||||
Three months ended September 30
|
|
|
|
|
||||||||||||
Total issuances
|
0.3 | $ | 16 | 0.3 | $ | 14 | ||||||||||
Issuances through 401(k) and/or IPP
|
- | - | 0.3 | 13 | ||||||||||||
Nine months ended September 30
|
||||||||||||||||
Total issuances
|
1.7 | $ | 42 | 11.8 | $ | 419 | ||||||||||
Issuances through 401(k) and/or IPP
|
- | 1 | 11.0 | 418 |
6. | PREFERRED STOCK OF SUBSIDIARIES |
7. | DEBT AND CREDIT FACILITIES |
8. | FAIR VALUE DISCLOSURES |
A. | DEBT AND INVESTMENTS |
(in millions)
|
Fair Value
|
Unrealized
Losses
|
Unrealized
Gains
|
|||||||||
September 30, 2011
|
|
|
|
|||||||||
Common stock equity
|
$ | 925 | $ | 41 | $ | 313 | ||||||
Preferred stock and other equity
|
50 | 1 | 8 | |||||||||
Corporate debt
|
90 | 1 | 6 | |||||||||
U.S. state and municipal debt
|
121 | 2 | 6 | |||||||||
U.S. and foreign government debt
|
289 | - | 17 | |||||||||
Money market funds and other
|
89 | - | 2 | |||||||||
Total
|
$ | 1,564 | $ | 45 | $ | 352 | ||||||
|
||||||||||||
December 31, 2010
|
||||||||||||
Common stock equity
|
$ | 1,021 | $ | 13 | $ | 408 | ||||||
Preferred stock and other equity
|
28 | - | 11 | |||||||||
Corporate debt
|
90 | - | 6 | |||||||||
U.S. state and municipal debt
|
132 | 4 | 3 | |||||||||
U.S. and foreign government debt
|
264 | 2 | 10 | |||||||||
Money market funds and other
|
52 | - | 1 | |||||||||
Total
|
$ | 1,587 | $ | 19 | $ | 439 |
(in millions)
|
|
|||
Due in one year or less
|
$ | 35 | ||
Due after one through five years
|
212 | |||
Due after five through 10 years
|
127 | |||
Due after 10 years
|
140 | |||
Total
|
$ | 514 |
|
Three months ended
September 30
|
Nine months ended
September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Proceeds
|
$ | 1,062 | $ | 2,051 | $ | 4,254 | $ | 5,743 | ||||||||
Realized gains
|
9 | 7 | 24 | 17 | ||||||||||||
Realized losses
|
11 | 5 | 20 | 20 |
(in millions)
|
Fair Value
|
Unrealized
Losses
|
Unrealized
Gains
|
|||||||||
September 30, 2011
|
|
|
|
|||||||||
Common stock equity
|
$ | 599 | $ | 27 | $ | 198 | ||||||
Preferred stock and other equity
|
15 | 1 | 5 | |||||||||
Corporate debt
|
72 | 1 | 5 | |||||||||
U.S. state and municipal debt
|
53 | - | 3 | |||||||||
U.S. and foreign government debt
|
213 | - | 16 | |||||||||
Money market funds and other
|
41 | - | 1 | |||||||||
Total
|
$ | 993 | $ | 29 | $ | 228 | ||||||
|
||||||||||||
December 31, 2010
|
||||||||||||
Common stock equity
|
$ | 652 | $ | 10 | $ | 256 | ||||||
Preferred stock and other equity
|
14 | - | 6 | |||||||||
Corporate debt
|
72 | - | 5 | |||||||||
U.S. state and municipal debt
|
51 | 1 | 1 | |||||||||
U.S. and foreign government debt
|
199 | 1 | 9 | |||||||||
Money market funds and other
|
42 | - | 1 | |||||||||
Total
|
$ | 1,030 | $ | 12 | $ | 278 |
(in millions)
|
|
|||
Due in one year or less
|
$ | 15 | ||
Due after one through five years
|
147 | |||
Due after five through 10 years
|
77 | |||
Due after 10 years
|
110 | |||
Total
|
$ | 349 |
|
Three months ended
September 30
|
Nine months ended
September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Proceeds
|
$ | 136 | $ | 88 | $ | 386 | $ | 310 | ||||||||
Realized gains
|
4 | 3 | 10 | 9 | ||||||||||||
Realized losses
|
4 | 3 | 9 | 15 |
(in millions)
|
Fair Value
|
Unrealized
Losses
|
Unrealized
Gains
|
|||||||||
September 30, 2011
|
|
|
|
|||||||||
Common stock equity
|
$ | 326 | $ | 14 | $ | 115 | ||||||
Preferred stock and other equity
|
35 | - | 3 | |||||||||
Corporate debt
|
18 | - | 1 | |||||||||
U.S. state and municipal debt
|
68 | 2 | 3 | |||||||||
U.S. and foreign government debt
|
76 | - | 1 | |||||||||
Money market funds and other
|
41 | - | 1 | |||||||||
Total
|
$ | 564 | $ | 16 | $ | 124 | ||||||
|
||||||||||||
December 31, 2010
|
||||||||||||
Common stock equity
|
$ | 369 | $ | 3 | $ | 152 | ||||||
Preferred stock and other equity
|
14 | - | 5 | |||||||||
Corporate debt
|
14 | - | 1 | |||||||||
U.S. state and municipal debt
|
81 | 3 | 2 | |||||||||
U.S. and foreign government debt
|
62 | 1 | 1 | |||||||||
Money market funds and other
|
10 | - | - | |||||||||
Total
|
$ | 550 | $ | 7 | $ | 161 |
(in millions)
|
|
|||
Due in one year or less
|
$ | 20 | ||
Due after one through five years
|
65 | |||
Due after five through 10 years
|
50 | |||
Due after 10 years
|
30 | |||
Total
|
$ | 165 |
|
Three months ended
September 30
|
Nine months ended
September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Proceeds
|
$ | 926 | $ | 1,891 | $ | 3,861 | $ | 5,305 | ||||||||
Realized gains
|
5 | 3 | 14 | 7 | ||||||||||||
Realized losses
|
7 | 2 | 11 | 5 |
B. | FAIR VALUE MEASUREMENTS |
PROGRESS ENERGY
|
|
|
|
|
||||||||||||
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
September 30, 2011
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
||||||||||||
Nuclear decommissioning trust funds
|
|
|
|
|
||||||||||||
Common stock equity
|
$ | 925 | $ | - | $ | - | $ | 925 | ||||||||
Preferred stock and other equity
|
23 | 27 | - | 50 | ||||||||||||
Corporate debt
|
- | 90 | - | 90 | ||||||||||||
U.S. state and municipal debt
|
1 | 118 | - | 119 | ||||||||||||
U.S. and foreign government debt
|
100 | 188 | - | 288 | ||||||||||||
Money market funds and other
|
- | 40 | - | 40 | ||||||||||||
Total nuclear decommissioning trust funds
|
1,049 | 463 | - | 1,512 | ||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
- | 7 | - | 7 | ||||||||||||
Other marketable securities
|
||||||||||||||||
Money market and other
|
18 | 7 | - | 25 | ||||||||||||
Total assets
|
$ | 1,067 | $ | 477 | $ | - | $ | 1,544 | ||||||||
|
||||||||||||||||
Liabilities
|
||||||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
$ | - | $ | 426 | $ | 43 | $ | 469 | ||||||||
Interest rate contracts
|
- | 86 | - | 86 | ||||||||||||
Contingent value obligations
|
- | - | 74 | 74 | ||||||||||||
Total liabilities
|
$ | - | $ | 512 | $ | 117 | $ | 629 |
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
December 31, 2010
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
||||||||||||
Nuclear decommissioning trust funds
|
|
|
|
|
||||||||||||
Common stock equity
|
$ | 1,021 | $ | - | $ | - | $ | 1,021 | ||||||||
Preferred stock and other equity
|
22 | 6 | - | 28 | ||||||||||||
Corporate debt
|
- | 86 | - | 86 | ||||||||||||
U.S. state and municipal debt
|
- | 132 | - | 132 | ||||||||||||
U.S. and foreign government debt
|
79 | 182 | - | 261 | ||||||||||||
Money market funds and other
|
1 | 42 | - | 43 | ||||||||||||
Total nuclear decommissioning trust funds
|
1,123 | 448 | - | 1,571 | ||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
- | 15 | - | 15 | ||||||||||||
Interest rate contracts
|
- | 4 | - | 4 | ||||||||||||
Other marketable securities
|
||||||||||||||||
Corporate debt
|
- | 4 | - | 4 | ||||||||||||
U.S. and foreign government debt
|
- | 3 | - | 3 | ||||||||||||
Money market and other
|
18 | - | - | 18 | ||||||||||||
Total assets
|
$ | 1,141 | $ | 474 | $ | - | $ | 1,615 | ||||||||
|
||||||||||||||||
Liabilities
|
||||||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
$ | - | $ | 458 | $ | 36 | $ | 494 | ||||||||
Interest rate contracts
|
- | 39 | - | 39 | ||||||||||||
Contingent value obligations
|
- | 15 | - | 15 | ||||||||||||
Total liabilities
|
$ | - | $ | 512 | $ | 36 | $ | 548 |
PEC
|
|
|
|
|
||||||||||||
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
September 30, 2011
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
||||||||||||
Nuclear decommissioning trust funds
|
|
|
|
|
||||||||||||
Common stock equity
|
$ | 599 | $ | - | $ | - | $ | 599 | ||||||||
Preferred stock and other equity
|
15 | - | - | 15 | ||||||||||||
Corporate debt
|
- | 72 | - | 72 | ||||||||||||
U.S. state and municipal debt
|
1 | 52 | - | 53 | ||||||||||||
U.S. and foreign government debt
|
89 | 124 | - | 213 | ||||||||||||
Money market funds and other
|
- | 40 | - | 40 | ||||||||||||
Total nuclear decommissioning trust funds
|
704 | 288 | - | 992 | ||||||||||||
Other marketable securities
|
3 | - | - | 3 | ||||||||||||
Total assets
|
$ | 707 | $ | 288 | $ | - | $ | 995 | ||||||||
|
||||||||||||||||
Liabilities
|
||||||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
$ | - | $ | 92 | $ | 42 | $ | 134 | ||||||||
Interest rate contracts
|
- | 43 | - | 43 | ||||||||||||
Total liabilities
|
$ | - | $ | 135 | $ | 42 | $ | 177 |
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
December 31, 2010
|
||||||||||||||||
Assets
|
||||||||||||||||
Nuclear decommissioning trust funds
|
||||||||||||||||
Common stock equity
|
$ | 652 | $ | - | $ | - | $ | 652 | ||||||||
Preferred stock and other equity
|
14 | - | - | 14 | ||||||||||||
Corporate debt
|
- | 72 | - | 72 | ||||||||||||
U.S. state and municipal debt
|
- | 51 | - | 51 | ||||||||||||
U.S. and foreign government debt
|
76 | 123 | - | 199 | ||||||||||||
Money market funds and other
|
1 | 28 | - | 29 | ||||||||||||
Total nuclear decommissioning trust funds
|
743 | 274 | - | 1,017 | ||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
- | 2 | - | 2 | ||||||||||||
Interest rate contracts
|
- | 3 | - | 3 | ||||||||||||
Other marketable securities
|
4 | - | - | 4 | ||||||||||||
Total assets
|
$ | 747 | $ | 279 | $ | - | $ | 1,026 | ||||||||
|
||||||||||||||||
Liabilities
|
||||||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
$ | - | $ | 87 | $ | 36 | $ | 123 | ||||||||
Interest rate contracts
|
- | 11 | - | 11 | ||||||||||||
Total liabilities
|
$ | - | $ | 98 | $ | 36 | $ | 134 |
PEF
|
|
|
|
|
||||||||||||
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
September 30, 2011
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
||||||||||||
Nuclear decommissioning trust funds
|
|
|
|
|
||||||||||||
Common stock equity
|
$ | 326 | $ | - | $ | - | $ | 326 | ||||||||
Preferred stock and other equity
|
8 | 27 | - | 35 | ||||||||||||
Corporate debt
|
- | 18 | - | 18 | ||||||||||||
U.S. state and municipal debt
|
- | 66 | - | 66 | ||||||||||||
U.S. and foreign government debt
|
11 | 64 | - | 75 | ||||||||||||
Total nuclear decommissioning trust funds
|
345 | 175 | - | 520 | ||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
- | 7 | - | 7 | ||||||||||||
Other marketable securities
|
1 | - | - | 1 | ||||||||||||
Total assets
|
$ | 346 | $ | 182 | $ | - | $ | 528 | ||||||||
|
||||||||||||||||
Liabilities
|
||||||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
$ | - | $ | 334 | $ | 1 | $ | 335 | ||||||||
Interest rate contracts
|
- | 8 | - | 8 | ||||||||||||
Total liabilities
|
$ | - | $ | 342 | $ | 1 | $ | 343 |
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
December 31, 2010
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
||||||||||||
Nuclear decommissioning trust funds
|
|
|
|
|
||||||||||||
Common stock equity
|
$ | 369 | $ | - | $ | - | $ | 369 | ||||||||
Preferred stock and other equity
|
8 | 6 | - | 14 | ||||||||||||
Corporate debt
|
- | 14 | - | 14 | ||||||||||||
U.S. state and municipal debt
|
- | 81 | - | 81 | ||||||||||||
U.S. and foreign government debt
|
3 | 59 | - | 62 | ||||||||||||
Money market funds and other
|
- | 14 | - | 14 | ||||||||||||
Total nuclear decommissioning trust funds
|
380 | 174 | - | 554 | ||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
- | 13 | - | 13 | ||||||||||||
Other marketable securities
|
1 | - | - | 1 | ||||||||||||
Total assets
|
$ | 381 | $ | 187 | $ | - | $ | 568 | ||||||||
|
||||||||||||||||
Liabilities
|
||||||||||||||||
Derivatives
|
||||||||||||||||
Commodity forward contracts
|
$ | - | $ | 371 | $ | - | $ | 371 | ||||||||
Interest rate contracts
|
- | 7 | - | 7 | ||||||||||||
Total liabilities
|
$ | - | $ | 378 | $ | - | $ | 378 |
PROGRESS ENERGY
|
||||||||||||||||
|
Three months ended
September 30
|
Nine months ended
September 30
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Derivatives, net at beginning of period
|
$ | 37 | $ | 62 | $ | 36 | $ | 39 | ||||||||
Total losses, realized and unrealized - commodities
|
||||||||||||||||
deferred as regulatory assets and liabilities, net
|
6 | 23 | 7 | 46 | ||||||||||||
Transfers in (out) of Level 3, net - CVOs
|
74 | - | 74 | - | ||||||||||||
Derivatives, net at end of period
|
$ | 117 | $ | 85 | $ | 117 | $ | 85 |
PEC
|
||||||||||||||||
|
Three months ended
September 30
|
Nine months ended
September 30
|
||||||||||||||
(in millions)
|
2011 | 2010 | 2011 | 2010 | ||||||||||||
Derivatives, net at beginning of period
|
$ | 37 | $ | 42 | $ | 36 | $ | 27 | ||||||||
Total losses, realized and unrealized - commodities
|
||||||||||||||||
deferred as regulatory assets and liabilities, net
|
5 | 13 | 6 | 28 | ||||||||||||
Derivatives, net at end of period
|
$ | 42 | $ | 55 | $ | 42 | $ | 55 |
PEF
|
||||||||||||||||
|
Three months ended
September 30
|
Nine months ended
September 30
|
||||||||||||||
(in millions)
|
2011 | 2010 | 2011 | 2010 | ||||||||||||
Derivatives, net at beginning of period
|
$ | - | $ | 20 | $ | - | $ | 12 | ||||||||
Total losses, realized and unrealized - commodities
|
||||||||||||||||
deferred as regulatory assets and liabilities, net
|
1 | 10 | 1 | 18 | ||||||||||||
Derivatives, net at end of period
|
$ | 1 | $ | 30 | $ | 1 | $ | 30 |
9. | INCOME TAXES |
10. | CONTINGENT VALUE OBLIGATIONS |
11. | BENEFIT PLANS |
PROGRESS ENERGY
|
|
|
||||||||||||||
Pension Benefits
|
OPEB
|
|||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service cost
|
$ | 13 | $ | 12 | $ | 3 | $ | 3 | ||||||||
Interest cost
|
35 | 35 | 10 | 13 | ||||||||||||
Expected return on plan assets
|
(45 | ) | (40 | ) | - | (1 | ) | |||||||||
Amortization of actuarial loss(a)
|
16 | 13 | 3 | 6 | ||||||||||||
Other amortization, net (a)
|
2 | 2 | 1 | 1 | ||||||||||||
Net periodic cost
|
$ | 21 | $ | 22 | $ | 17 | $ | 22 |
(a)
|
Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2010 Form 10-K.
|
PEC
|
|
|
||||||||||||||
Pension Benefits
|
OPEB
|
|||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service cost
|
$ | 5 | $ | 5 | $ | 2 | $ | 1 | ||||||||
Interest cost
|
16 | 16 | 5 | 6 | ||||||||||||
Expected return on plan assets
|
(23 | ) | (20 | ) | - | - | ||||||||||
Amortization of actuarial loss
|
7 | 4 | 1 | 3 | ||||||||||||
Other amortization, net
|
1 | 1 | - | - | ||||||||||||
Net periodic cost
|
$ | 6 | $ | 6 | $ | 8 | $ | 10 |
PEF
|
|
|
||||||||||||||
Pension Benefits
|
OPEB
|
|||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service cost
|
$ | 6 | $ | 6 | $ | 1 | $ | 1 | ||||||||
Interest cost
|
15 | 15 | 4 | 6 | ||||||||||||
Expected return on plan assets
|
(19 | ) | (17 | ) | - | - | ||||||||||
Amortization of actuarial loss
|
8 | 8 | 2 | 3 | ||||||||||||
Other amortization, net
|
- | - | 1 | 1 | ||||||||||||
Net periodic cost
|
$ | 10 | $ | 12 | $ | 8 | $ | 11 |
PROGRESS ENERGY
|
|
|
||||||||||||||
Pension Benefits
|
OPEB
|
|||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service cost
|
$ | 40 | $ | 36 | $ | 8 | $ | 7 | ||||||||
Interest cost
|
105 | 105 | 30 | 29 | ||||||||||||
Expected return on plan assets
|
(136 | ) | (119 | ) | (1 | ) | (3 | ) | ||||||||
Amortization of actuarial loss(a)
|
49 | 38 | 9 | 6 | ||||||||||||
Other amortization, net (a)
|
5 | 5 | 4 | 4 | ||||||||||||
Net periodic cost
|
$ | 63 | $ | 65 | $ | 50 | $ | 43 |
(a)
|
Adjusted to reflect PEF’s rate treatment. See Note 16B in the 2010 Form 10-K.
|
PEC
|
|
|
||||||||||||||
Pension Benefits
|
OPEB
|
|||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service cost
|
$ | 16 | $ | 14 | $ | 3 | $ | 4 | ||||||||
Interest cost
|
47 | 48 | 15 | 14 | ||||||||||||
Expected return on plan assets
|
(68 | ) | (58 | ) | - | (1 | ) | |||||||||
Amortization of actuarial loss
|
19 | 12 | 4 | 3 | ||||||||||||
Other amortization, net
|
4 | 4 | 1 | 1 | ||||||||||||
Net periodic cost
|
$ | 18 | $ | 20 | $ | 23 | $ | 21 |
PEF
|
|
|
||||||||||||||
Pension Benefits
|
OPEB
|
|||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Service cost
|
$ | 18 | $ | 16 | $ | 3 | $ | 2 | ||||||||
Interest cost
|
45 | 44 | 13 | 12 | ||||||||||||
Expected return on plan assets
|
(59 | ) | (51 | ) | (1 | ) | (1 | ) | ||||||||
Amortization of actuarial loss
|
25 | 23 | 6 | 3 | ||||||||||||
Other amortization, net
|
- | - | 3 | 3 | ||||||||||||
Net periodic cost
|
$ | 29 | $ | 32 | $ | 24 | $ | 19 |
12. | RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS |
A. | COMMODITY DERIVATIVES |
B. | INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES |
C. | CONTINGENT FEATURES |
D. | DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION |
Instrument / Balance sheet location
|
September 30, 2011
|
December 31, 2010
|
||||||||||||||
(in millions)
|
Asset
|
Liability
|
Asset
|
Liability
|
||||||||||||
Derivatives designated as hedging instruments
|
||||||||||||||||
Commodity cash flow derivatives
|
|
|
|
|
||||||||||||
Derivative liabilities, current
|
|
$ | 1 |
|
$ | - | ||||||||||
Interest rate derivatives
|
|
|
||||||||||||||
Prepayments and other current assets
|
$ | - | $ | 1 | ||||||||||||
Other assets and deferred debits
|
- | 3 | ||||||||||||||
Derivative liabilities, current
|
70 | 32 | ||||||||||||||
Derivative liabilities, long-term
|
16 | 7 | ||||||||||||||
Total derivatives designated as hedging instruments
|
- | 87 | 4 | 39 | ||||||||||||
Derivatives not designated as hedging instruments
|
||||||||||||||||
Commodity derivatives(a)
|
||||||||||||||||
Prepayments and other current assets
|
6 | 11 | ||||||||||||||
Other assets and deferred debits
|
1 | 4 | ||||||||||||||
Derivative liabilities, current
|
231 | 226 | ||||||||||||||
Derivative liabilities, long-term
|
237 | 268 | ||||||||||||||
CVOs(b)
|
||||||||||||||||
Other current liabilities | 74 | - | ||||||||||||||
Other liabilities and deferred credits
|
- | 15 | ||||||||||||||
Fair value of derivatives not designated as hedging instruments
|
7 | 542 | 15 | 509 | ||||||||||||
Fair value loss transition adjustment(c)
|
||||||||||||||||
Derivative liabilities, current
|
1 | 1 | ||||||||||||||
Derivative liabilities, long-term
|
2 | 3 | ||||||||||||||
Total derivatives not designated as hedging instruments
|
7 | 545 | 15 | 513 | ||||||||||||
Total derivatives
|
$ | 7 | $ | 632 | $ | 19 | $ | 552 |
(a)
|
Substantially all of these contracts receive regulatory treatment.
|
||||||||||||
(b)
|
As discussed in Note 10, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000.
|
||||||||||||
(c)
|
In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the adoption of new accounting guidance for derivatives. The related liability is being amortized to earnings over the term of the related contracts.
|
Derivatives Designated as Hedging Instruments
|
||||||||||||||||||||||||
Instrument
|
Amount of Gain or
(Loss) Recognized in
OCI, Net of Tax on
Derivatives(a)
|
Amount of Gain or
(Loss), Net of Tax
Reclassified from
Accumulated OCI into
Income(a)
|
Amount of Pre-tax Gain
or (Loss) Recognized in
Income on
Derivatives(b)
|
|||||||||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
Commodity cash flow derivatives(d)
|
$ | (1 | ) | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||
Interest rate derivatives(c) (e)
|
(68 | ) | (30 | ) | (2 | ) | (1 | ) | (1 | ) | - | |||||||||||||
Total
|
$ | (69 | ) | $ | (30 | ) | $ | (2 | ) | $ | (1 | ) | $ | (1 | ) | $ | - |
(a)
|
Effective portion.
|
|||||||||||||||||
(b)
|
Related to ineffective portion and amount excluded from effectiveness testing.
|
|||||||||||||||||
(c)
|
Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
|
|||||||||||||||||
(d)
|
Amounts recorded in the Consolidated Statements of Income are classified in fuel used in electric generation.
|
|||||||||||||||||
(e)
|
Amounts recorded in the Consolidated Statements of Income are classified in interest charges.
|
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||
Instrument
|
Realized Gain or (Loss)(a)
|
Unrealized Gain or (Loss)(b)
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Commodity derivatives
|
$ | (91 | ) | $ | (114 | ) | $ | (157 | ) | $ | (181 | ) |
(a)
|
After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
|
|||||||||||
(b)
|
Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.
|
Instrument
|
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Fair value loss transition adjustment(a)
|
$ | 1 | $ | 1 | ||||
CVOs(a)
|
(63 | ) | - | |||||
Total
|
$ | (62 | ) | $ | 1 |
(a)
|
Amounts recorded in the Consolidated Statements of Income are classified in other, net.
|
|||||
|
|
|
|
Derivatives Designated as Hedging Instruments
|
||||||||||||||||||||||||
Instrument
|
Amount of Gain or
(Loss) Recognized in
OCI, Net of Tax on
Derivatives(a)
|
Amount of Gain or
(Loss), Net of Tax
Reclassified from
Accumulated OCI into
Income(a)
|
Amount of Pre-tax Gain
or (Loss) Recognized in
ncome on
Derivatives(b)
|
|||||||||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
Commodity cash flow derivatives(d)
|
$ | (1 | ) | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||
Interest rate derivatives(c) (e)
|
(82 | ) | (80 | ) | (5 | ) | (4 | ) | (3 | ) | - | |||||||||||||
Total
|
$ | (83 | ) | $ | (80 | ) | $ | (5 | ) | $ | (4 | ) | $ | (3 | ) | $ | - |
(a)
|
Effective portion.
|
|||||||||||||||||
(b)
|
Related to ineffective portion and amount excluded from effectiveness testing.
|
|||||||||||||||||
(c)
|
Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
|
|||||||||||||||||
(d)
|
Amounts recorded in the Consolidated Statements of Income are classified in fuel used in electric generation.
|
|||||||||||||||||
(e)
|
Amounts recorded in the Consolidated Statements of Income are classified in interest charges.
|
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||
Instrument
|
Realized Gain or (Loss)(a)
|
Unrealized Gain or (Loss)(b)
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Commodity derivatives
|
$ | (219 | ) | $ | (264 | ) | $ | (201 | ) | $ | (417 | ) |
(a)
|
After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
|
|||||||||||
(b)
|
Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.
|
Instrument
|
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Commodity derivatives(a)
|
$ | 1 | $ | - | ||||
Fair value loss transition adjustment(a)
|
1 | 1 | ||||||
CVOs(a)
|
(59 | ) | - | |||||
Total
|
$ | (57 | ) | $ | 1 |
(a)
|
Amounts recorded in the Consolidated Statements of Income are classified in other, net.
|
PEC
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
The following table presents the fair value of derivative instruments at September 30, 2011 and December 31, 2010:
|
Instrument / Balance sheet location
|
September 30, 2011
|
December 31, 2010
|
||||||||||||||
(in millions)
|
Asset
|
Liability
|
Asset
|
Liability
|
||||||||||||
Derivatives designated as hedging instruments
|
||||||||||||||||
Interest rate derivatives
|
|
|
|
|
||||||||||||
Other assets and deferred debits
|
$ | - |
|
$ | 3 |
|
||||||||||
Derivative liabilities, current
|
$ | 35 | $ | 7 | ||||||||||||
Other liabilities and deferred credits
|
8 | 4 | ||||||||||||||
Total derivatives designated as hedging instruments
|
- | 43 | 3 | 11 | ||||||||||||
Derivatives not designated as hedging instruments
|
||||||||||||||||
Commodity derivatives(a)
|
||||||||||||||||
Prepayments and other current assets
|
- | 1 | ||||||||||||||
Other assets and deferred debits
|
- | 1 | ||||||||||||||
Derivative liabilities, current
|
57 | 45 | ||||||||||||||
Other liabilities and deferred credits
|
77 | 78 | ||||||||||||||
Fair value of derivatives not designated as hedging instruments
|
- | 134 | 2 | 123 | ||||||||||||
Fair value loss transition adjustment(b)
|
||||||||||||||||
Derivative liabilities, current
|
1 | 1 | ||||||||||||||
Other liabilities and deferred credits
|
2 | 3 | ||||||||||||||
Total derivatives not designated as hedging instruments
|
- | 137 | 2 | 127 | ||||||||||||
Total derivatives
|
$ | - | $ | 180 | $ | 5 | $ | 138 |
(a)
|
Substantially all of these contracts receive regulatory treatment.
|
||||||||||||
(b)
|
In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the adoption of new accounting guidance for derivatives. The related liability is being amortized to earnings over the term of the related contracts.
|
The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the three months ended September 30, 2011 and 2010:
|
Derivatives Designated as Hedging Instruments
|
||||||||||||||||||||||||
Instrument
|
Amount of Gain or
(Loss) Recognized in
OCI, Net of Tax on
Derivatives(a)
|
Amount of Gain or
(Loss), Net of Tax
Reclassified from
Accumulated OCI into
Income(a)
|
Amount of Pre-tax Gain
or (Loss) Recognized in
Income on
Derivatives(b)
|
|||||||||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
Interest rate derivatives(c) (d)
|
$ | (35 | ) | $ | (10 | ) | $ | (1 | ) | $ | (1 | ) | $ | (1 | ) | $ | - |
(a)
|
Effective portion.
|
|||||||||||||||||
(b)
|
Related to ineffective portion and amount excluded from effectiveness testing.
|
|||||||||||||||||
(c)
|
Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
|
|||||||||||||||||
(d)
|
Amounts recorded in the Consolidated Statements of Income are classified in interest charges.
|
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||
Instrument
|
Realized Gain or (Loss)(a)
|
Unrealized Gain or (Loss)(b)
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Commodity derivatives
|
$ | (20 | ) | $ | (17 | ) | $ | (42 | ) | $ | (38 | ) |
(a)
|
After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
|
|||||||||||
(b)
|
Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.
|
Instrument
|
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Fair value loss transition adjustment(a)
|
$ | 1 | $ | 1 |
(a)
|
Amounts recorded in the Consolidated Statements of Income are classified in other, net.
|
The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the nine months ended September 30, 2011 and 2010:
|
Derivatives Designated as Hedging Instruments
|
||||||||||||||||||||||||
Instrument
|
Amount of Gain or
(Loss) Recognized
in OCI, Net of Tax
on Derivatives(a)
|
Amount of Gain or
(Loss), Net of Tax
Reclassified from
Accumulated OCI
into Income(a)
|
Amount of Pre-tax
Gain or (Loss)
Recognized in
Income on
Derivatives(b)
|
|||||||||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
Interest rate derivatives(c) (d)
|
$ | (40 | ) | $ | (26 | ) | $ | (3 | ) | $ | (3 | ) | $ | (1 | ) | $ | - |
(a)
|
Effective portion.
|
|||||||||||||||||
(b)
|
Related to ineffective portion and amount excluded from effectiveness testing.
|
|||||||||||||||||
(c)
|
Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
|
|||||||||||||||||
(d)
|
Amounts recorded in the Consolidated Statements of Income are classified in interest charges.
|
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||
Instrument
|
Realized Gain or (Loss)(a)
|
Unrealized Gain or (Loss)(b)
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Commodity derivatives
|
$ | (42 | ) | $ | (36 | ) | $ | (55 | ) | $ | (82 | ) |
(a)
|
After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
|
|||||||||||
(b)
|
Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.
|
Instrument
|
Amount of Gain or (Loss)
Recognized in Income on
Derivatives
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Commodity derivatives(a)
|
$ | 1 | $ | - | ||||
Fair value loss transition adjustment(a)
|
1 | 1 | ||||||
Total
|
$ | 2 | $ | 1 |
(a)
|
Amounts recorded in the Consolidated Statements of Income are classified in other, net.
|
PEF
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
||
The following table presents the fair value of derivative instruments at September 30, 2011 and December 31, 2010:
|
Instrument / Balance sheet location
|
September 30, 2011
|
December 31, 2010
|
||||||||||||||
(in millions)
|
Asset
|
Liability
|
Asset
|
Liability
|
||||||||||||
Derivatives designated as hedging instruments
|
||||||||||||||||
Commodity cash flow derivatives
|
|
|
|
|
||||||||||||
Derivative liabilities, current
|
|
$ | 1 |
|
$ | - | ||||||||||
Interest rate derivatives
|
|
|
||||||||||||||
Derivative liabilities, current
|
|
- |
|
7 | ||||||||||||
Derivative liabilities, long-term
|
|
8 |
|
- | ||||||||||||
Total derivatives designated as hedging instruments
|
|
9 |
|
7 | ||||||||||||
|
|
|||||||||||||||
Derivatives not designated as hedging instruments
|
||||||||||||||||
Commodity derivatives(a)
|
|
|
||||||||||||||
Prepayments and other current assets
|
$ | 6 | $ | 10 | ||||||||||||
Other assets and deferred debits
|
1 | 3 | ||||||||||||||
Derivative liabilities, current
|
174 | 181 | ||||||||||||||
Derivative liabilities, long-term
|
160 | 190 | ||||||||||||||
Total derivatives not designated as hedging instruments
|
7 | 334 | 13 | 371 | ||||||||||||
Total derivatives
|
$ | 7 | $ | 343 | $ | 13 | $ | 378 |
(a)
|
Substantially all of these contracts receive regulatory treatment.
|
The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Statements of Income for the three months ended September 30, 2011 and 2010:
|
Derivatives Designated as Hedging Instruments
|
||||||||||||||||||||||||
Instrument
|
Amount of Gain or
(Loss) Recognized in
OCI, Net of Tax on
Derivatives(a)
|
Amount of Gain or
(Loss), Net of Tax
Reclassified from
Accumulated OCI into
Income(a)
|
Amount of Pre-tax Gain
or (Loss) Recognized in
Income on
Derivatives(b)
|
|||||||||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
Commodity cash flow derivatives(d)
|
$ | (1 | ) | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||
Interest rate derivatives(c) (e)
|
(16 | ) | (6 | ) | - | - | - | - | ||||||||||||||||
Total
|
$ | (17 | ) | $ | (6 | ) | $ | - | $ | - | $ | - | $ | - |
(a)
|
Effective portion.
|
|||||||||||||||||
(b)
|
Related to ineffective portion and amount excluded from effectiveness testing.
|
|||||||||||||||||
(c)
|
Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
|
|||||||||||||||||
(d)
|
Amounts recorded in the Statements of Income are classified in fuel used in electric generation.
|
|||||||||||||||||
(e)
|
Amounts recorded in the Statements of Income are classified in interest charges.
|
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||
Instrument
|
Realized Gain or (Loss)(a)
|
Unrealized Gain or (Loss)(b)
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Commodity derivatives
|
$ | (71 | ) | $ | (97 | ) | $ | (115 | ) | $ | (143 | ) |
(a)
|
After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
|
|||||||||||
(b)
|
Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.
|
The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Statements of Income for the nine months ended September 30, 2011 and 2010:
|
Derivatives Designated as Hedging Instruments
|
||||||||||||||||||||||||
Instrument
|
Amount of Gain or
(Loss) Recognized in
OCI, Net of Tax on
Derivatives(a)
|
Amount of Gain or
(Loss), Net of Tax
Reclassified from
Accumulated OCI into
Income(a)
|
Amount of Pre-tax Gain
or (Loss) Recognized in
Income on
Derivatives(b)
|
|||||||||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
2011
|
2010
|
||||||||||||||||||
Commodity cash flow derivatives(d)
|
$ | (1 | ) | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||
Interest rate derivatives(c) (e)
|
(21 | ) | (16 | ) | - | - | - | - | ||||||||||||||||
Total
|
$ | (22 | ) | $ | (16 | ) | $ | - | $ | - | $ | - | $ | - |
(a)
|
Effective portion.
|
|||||||||||||||||
(b)
|
Related to ineffective portion and amount excluded from effectiveness testing.
|
|||||||||||||||||
(c)
|
Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
|
|||||||||||||||||
(d)
|
Amounts recorded in the Consolidated Statements of Income are classified in fuel used in electric generation.
|
|||||||||||||||||
(e)
|
Amounts recorded in the Consolidated Statements of Income are classified in interest charges.
|
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||
Instrument
|
Realized Gain or (Loss)(a)
|
Unrealized Gain or (Loss)(b)
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Commodity derivatives
|
$ | (177 | ) | $ | (228 | ) | $ | (146 | ) | $ | (335 | ) |
(a)
|
After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
|
|||||||||||
(b)
|
Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.
|
13. | FINANCIAL INFORMATION BY BUSINESS SEGMENT |
(in millions)
|
PEC
|
PEF
|
Corporate
and Other
|
Eliminations
|
Totals
|
|||||||||||||||
At and for the three months ended September 30, 2011
|
|
|
|
|||||||||||||||||
Revenues
|
|
|
|
|
|
|||||||||||||||
Unaffiliated
|
$ | 1,332 | $ | 1,413 | $ | 2 | $ | - | $ | 2,747 | ||||||||||
Intersegment
|
- | 1 | 69 | (70 | ) | - | ||||||||||||||
Total revenues
|
1,332 | 1,414 | 71 | (70 | ) | 2,747 | ||||||||||||||
Ongoing Earnings
|
202 | 202 | (60 | ) | - | 344 | ||||||||||||||
Total Assets
|
15,543 | 14,014 | 20,954 | (16,834 | ) | 33,677 | ||||||||||||||
|
||||||||||||||||||||
For the three months ended September 30, 2010
|
||||||||||||||||||||
Revenues
|
||||||||||||||||||||
Unaffiliated
|
$ | 1,414 | $ | 1,543 | $ | 5 | $ | - | $ | 2,962 | ||||||||||
Intersegment
|
- | - | 66 | (66 | ) | - | ||||||||||||||
Total revenues
|
1,414 | 1,543 | 71 | (66 | ) | 2,962 | ||||||||||||||
Ongoing Earnings
|
233 | 177 | (49 | ) | - | 361 | ||||||||||||||
|
|
|||||||||||||||||||
For the nine months ended September 30, 2011
|
||||||||||||||||||||
Revenues
|
||||||||||||||||||||
Unaffiliated
|
$ | 3,525 | $ | 3,637 | $ | 8 | $ | - | $ | 7,170 | ||||||||||
Intersegment
|
- | 2 | 203 | (205 | ) | - | ||||||||||||||
Total revenues
|
3,525 | 3,639 | 211 | (205 | ) | 7,170 | ||||||||||||||
Ongoing Earnings
|
453 | 454 | (150 | ) | - | 757 | ||||||||||||||
|
||||||||||||||||||||
For the nine months ended September 30, 2010
|
||||||||||||||||||||
Revenues
|
||||||||||||||||||||
Unaffiliated
|
$ | 3,794 | $ | 4,064 | $ | 11 | $ | - | $ | 7,869 | ||||||||||
Intersegment
|
- | 1 | 179 | (180 | ) | - | ||||||||||||||
Total revenues
|
3,794 | 4,065 | 190 | (180 | ) | 7,869 | ||||||||||||||
Ongoing Earnings
|
493 | 409 | (146 | ) | - | 756 |
|
For the three months ended September 30
|
|||||||
(in millions)
|
2011
|
2010
|
||||||
Ongoing Earnings
|
$ | 344 | $ | 361 | ||||
Tax levelization
|
8 | 4 | ||||||
CVO mark-to-market, net of tax benefit of $13 (Note 10)
|
(50 | ) | - | |||||
Impairment, net of tax benefit of $1
|
- | (2 | ) | |||||
Merger and integration costs, net of tax benefit of $7 (Note 2)
|
(15 | ) | - | |||||
CR3 indemnification adjustment, net of tax expense of $2 (Note 15B)
|
4 | - | ||||||
Continuing income attributable to noncontrolling interests, net of tax
|
2 | 2 | ||||||
Income from continuing operations before cumulative effect of change in
accounting principle
|
293 | 365 | ||||||
Discontinued operations, net of tax
|
- | (2 | ) | |||||
Cumulative effect of change in accounting principle, net of tax
|
- | 2 | ||||||
Net income attributable to noncontrolling interests, net of tax
|
(2 | ) | (4 | ) | ||||
Net income attributable to controlling interests
|
$ | 291 | $ | 361 | ||||
|
||||||||
|
For the nine months ended September 30
|
|||||||
(in millions)
|
2011 | 2010 | ||||||
Ongoing Earnings
|
$ | 757 | $ | 756 | ||||
Tax levelization
|
2 | 3 | ||||||
CVO mark-to-market, net of tax benefit of $13 (Note 10)
|
(46 | ) | - | |||||
Impairment, net of tax benefit of $3
|
- | (5 | ) | |||||
Plant retirement adjustment, net of tax expense of $1
|
- | 1 | ||||||
Change in tax treatment of the Medicare Part D subsidy (Note 11)
|
- | (22 | ) | |||||
Merger and integration costs, net of tax benefit of $11 (Note 2)
|
(36 | ) | - | |||||
CR3 indemnification charge, net of tax benefit of $16 (Note 15B)
|
(22 | ) | - | |||||
Continuing income attributable to noncontrolling interests, net of tax
|
5 | 4 | ||||||
Income from continuing operations
|
660 | 737 | ||||||
Discontinued operations, net of tax
|
(4 | ) | (2 | ) | ||||
Net income attributable to noncontrolling interests, net of tax
|
(5 | ) | (4 | ) | ||||
Net income attributable to controlling interests
|
$ | 651 | $ | 731 |
14. | ENVIRONMENTAL MATTERS |
A. | HAZARDOUS AND SOLID WASTE |
PROGRESS ENERGY
|
|
|
|
|||||||||
(in millions)
|
MGP and
Other Sites
|
Remediation
of Distribution
and Substation Transformers
|
Total
|
|||||||||
Balance, December 31, 2010
|
$ | 20 | $ | 15 | $ | 35 | ||||||
Amount accrued for environmental loss contingencies(a)
|
1 | 6 | 7 | |||||||||
Expenditures for environmental loss contingencies(b)
|
(4 | ) | (13 | ) | (17 | ) | ||||||
Balance, September 30, 2011(c)
|
$ | 17 | $ | 8 | $ | 25 | ||||||
Balance, December 31, 2009
|
$ | 22 | $ | 20 | $ | 42 | ||||||
Amount accrued for environmental loss contingencies(a)
|
7 | 11 | 18 | |||||||||
Expenditures for environmental loss contingencies(b)
|
(8 | ) | (14 | ) | (22 | ) | ||||||
Balance, September 30, 2010(c)
|
$ | 21 | $ | 17 | $ | 38 |
(a)
|
Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, our accruals for environmental loss contingencies were not material.
|
||||||||
(b)
|
Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011, our expenditures for environmental loss contingencies were not material. For the three months ended September 30, 2010, our expenditures were not material for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
|
||||||||
(c)
|
Expected to be paid out over one to 15 years.
|
PEC
|
|
|||
(in millions)
|
MGP and
Other Sites
|
|||
Balance, December 31, 2010
|
$ | 12 | ||
Amount accrued for environmental loss contingencies(a)
|
- | |||
Expenditures for environmental loss contingencies(b)
|
(1 | ) | ||
Balance, September 30, 2011(c)
|
$ | 11 | ||
Balance, December 31, 2009
|
$ | 13 | ||
Amount accrued for environmental loss contingencies(a)
|
3 | |||
Expenditures for environmental loss contingencies(b)
|
(4 | ) | ||
Balance, September 30, 2010(c)
|
$ | 12 |
(a)
|
Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEC's accruals for the remediation of MGP and other sites were not material.
|
||||||||
(b)
|
Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEC's expenditures for the remediation of MGP and other sites were not material.
|
||||||||
(c)
|
Expected to be paid out over one to five years.
|
|
|
|
|
|
|
|
|
PEF
|
|
|
|
|||||||||
(in millions)
|
MGP and
Other Sites
|
Remediation
of Distribution
and Substation Transformers
|
Total
|
|||||||||
Balance, December 31, 2010
|
$ | 8 | $ | 15 | $ | 23 | ||||||
Amount accrued for environmental loss contingencies(a)
|
1 | 6 | 7 | |||||||||
Expenditures for environmental loss contingencies(b)
|
(3 | ) | (13 | ) | (16 | ) | ||||||
Balance, September 30, 2011(c)
|
$ | 6 | $ | 8 | $ | 14 | ||||||
Balance, December 31, 2009
|
$ | 9 | $ | 20 | $ | 29 | ||||||
Amount accrued for environmental loss contingencies(a)
|
4 | 11 | 15 | |||||||||
Expenditures for environmental loss contingencies(b)
|
(4 | ) | (14 | ) | (18 | ) | ||||||
Balance, September 30, 2010(c)
|
$ | 9 | $ | 17 | $ | 26 |
(a)
|
Amounts accrued are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011 and 2010, PEF's accruals for environmental loss contingencies were not material.
|
||||||||
(b)
|
Expenditures are for the nine months ended September 30, 2011 and 2010. For the three months ended September 30, 2011, PEF's expenditures were not material for the remediation of MGP and other sites and were $4 million for the remediation of distribution and substation transformers. For the three months ended September 30, 2010, PEF's expenditures were not material for the remediation of MGP and other sites and were $5 million for the remediation of distribution and substation transformers.
|
||||||||
(c)
|
Expected to be paid out over one to 15 years.
|
|
|
|
|
|
|
|
|
B. | AIR AND WATER QUALITY |
15. | COMMITMENTS AND CONTINGENCIES |
A. | PURCHASE OBLIGATIONS |
B. | GUARANTEES |
C.
|
OTHER COMMITMENTS AND CONTINGENCIES
|
16. | CONDENSED CONSOLIDATING STATEMENTS |
Condensed Consolidating Statement of Income
|
||||||||||||||||||||
Three months ended September 30, 2011
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
Operating revenues
|
|
|
|
|
|
|||||||||||||||
Operating revenues
|
$ | - | $ | 1,415 | $ | 1,332 | $ | - | $ | 2,747 | ||||||||||
Affiliate revenues
|
- | - | 69 | (69 | ) | - | ||||||||||||||
Total operating revenues
|
- | 1,415 | 1,401 | (69 | ) | 2,747 | ||||||||||||||
Operating expenses
|
||||||||||||||||||||
Fuel used in electric generation
|
- | 456 | 388 | - | 844 | |||||||||||||||
Purchased power
|
- | 232 | 117 | - | 349 | |||||||||||||||
Operation and maintenance
|
2 | 221 | 332 | (68 | ) | 487 | ||||||||||||||
Depreciation, amortization and accretion
|
- | 39 | 136 | - | 175 | |||||||||||||||
Taxes other than on income
|
- | 106 | 58 | (1 | ) | 163 | ||||||||||||||
Other
|
- | 1 | 38 | - | 39 | |||||||||||||||
Total operating expenses
|
2 | 1,055 | 1,069 | (69 | ) | 2,057 | ||||||||||||||
Operating (loss) income
|
(2 | ) | 360 | 332 | - | 690 | ||||||||||||||
Other income (expense)
|
||||||||||||||||||||
Interest income
|
- | - | 1 | - | 1 | |||||||||||||||
Allowance for equity funds used during construction
|
- | 7 | 15 | - | 22 | |||||||||||||||
Other, net
|
(63 | ) | (1 | ) | (5 | ) | (1 | ) | (70 | ) | ||||||||||
Total other (expense) income, net
|
(63 | ) | 6 | 11 | (1 | ) | (47 | ) | ||||||||||||
Interest charges
|
||||||||||||||||||||
Interest charges
|
80 | 56 | 45 | (1 | ) | 180 | ||||||||||||||
Allowance for borrowed funds used during construction
|
- | (4 | ) | (4 | ) | - | (8 | ) | ||||||||||||
Total interest charges, net
|
80 | 52 | 41 | (1 | ) | 172 | ||||||||||||||
(Loss) income from continuing operations before
income tax and equity in earnings of consolidated
subsidiaries
|
(145 | ) | 314 | 302 | - | 471 | ||||||||||||||
Income tax (benefit) expense
|
(45 | ) | 116 | 103 | 4 | 178 | ||||||||||||||
Equity in earnings of consolidated subsidiaries
|
391 | - | - | (391 | ) | - | ||||||||||||||
Income from continuing operations
|
291 | 198 | 199 | (395 | ) | 293 | ||||||||||||||
Discontinued operations, net of tax
|
- | 1 | (1 | ) | - | - | ||||||||||||||
Net income
|
291 | 199 | 198 | (395 | ) | 293 | ||||||||||||||
Net income attributable to noncontrolling
interests, net of tax
|
- | (1 | ) | - | (1 | ) | (2 | ) | ||||||||||||
Net income attributable to controlling interests
|
$ | 291 | $ | 198 | $ | 198 | $ | (396 | ) | $ | 291 | |||||||||
|
Condensed Consolidating Statement of Income
|
||||||||||||||||||||
Three months ended September 30, 2010
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
Operating revenues
|
|
|
|
|
|
|||||||||||||||
Operating revenues
|
$ | - | $ | 1,548 | $ | 1,414 | $ | - | $ | 2,962 | ||||||||||
Affiliate revenues
|
- | - | 66 | (66 | ) | - | ||||||||||||||
Total operating revenues
|
- | 1,548 | 1,480 | (66 | ) | 2,962 | ||||||||||||||
Operating expenses
|
||||||||||||||||||||
Fuel used in electric generation
|
- | 471 | 464 | - | 935 | |||||||||||||||
Purchased power
|
- | 309 | 109 | - | 418 | |||||||||||||||
Operation and maintenance
|
2 | 234 | 301 | (63 | ) | 474 | ||||||||||||||
Depreciation, amortization and accretion
|
- | 77 | 124 | - | 201 | |||||||||||||||
Taxes other than on income
|
- | 102 | 60 | (1 | ) | 161 | ||||||||||||||
Other
|
- | 10 | 10 | - | 20 | |||||||||||||||
Total operating expenses
|
2 | 1,203 | 1,068 | (64 | ) | 2,209 | ||||||||||||||
Operating (loss) income
|
(2 | ) | 345 | 412 | (2 | ) | 753 | |||||||||||||
Other income (expense)
|
||||||||||||||||||||
Interest income
|
2 | 1 | 2 | (2 | ) | 3 | ||||||||||||||
Allowance for equity funds used during construction
|
- | 5 | 17 | - | 22 | |||||||||||||||
Other, net
|
- | (3 | ) | (3 | ) | 1 | (5 | ) | ||||||||||||
Total other income, net
|
2 | 3 | 16 | (1 | ) | 20 | ||||||||||||||
Interest charges
|
||||||||||||||||||||
Interest charges
|
71 | 74 | 53 | (1 | ) | 197 | ||||||||||||||
Allowance for borrowed funds used during construction
|
- | (3 | ) | (5 | ) | - | (8 | ) | ||||||||||||
Total interest charges, net
|
71 | 71 | 48 | (1 | ) | 189 | ||||||||||||||
(Loss) income from continuing operations before
income tax and equity in earnings of consolidated
subsidiaries
|
(71 | ) | 277 | 380 | (2 | ) | 584 | |||||||||||||
Income tax (benefit) expense
|
(25 | ) | 99 | 147 | (2 | ) | 219 | |||||||||||||
Equity in earnings of consolidated subsidiaries
|
406 | - | - | (406 | ) | - | ||||||||||||||
Income from continuing operations before
cumulative effect of change in accounting principle
|
360 | 178 | 233 | (406 | ) | 365 | ||||||||||||||
Discontinued operations, net of tax
|
1 | (1 | ) | (2 | ) | - | (2 | ) | ||||||||||||
Cumulative effect of change in accounting principle,
net of tax
|
- | - | 2 | - | 2 | |||||||||||||||
Net income
|
361 | 177 | 233 | (406 | ) | 365 | ||||||||||||||
Net income attributable to noncontrolling
interests, net of tax
|
- | (1 | ) | (2 | ) | (1 | ) | (4 | ) | |||||||||||
Net income attributable to controlling interests
|
$ | 361 | $ | 176 | $ | 231 | $ | (407 | ) | $ | 361 |
Condensed Consolidating Statement of Income
|
||||||||||||||||||||
Nine months ended September 30, 2011
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
Operating revenues
|
|
|
|
|
|
|||||||||||||||
Operating revenues
|
$ | - | $ | 3,645 | $ | 3,525 | $ | - | $ | 7,170 | ||||||||||
Affiliate revenues
|
- | - | 204 | (204 | ) | - | ||||||||||||||
Total operating revenues
|
- | 3,645 | 3,729 | (204 | ) | 7,170 | ||||||||||||||
Operating expenses
|
||||||||||||||||||||
Fuel used in electric generation
|
- | 1,159 | 1,077 | - | 2,236 | |||||||||||||||
Purchased power
|
- | 641 | 257 | - | 898 | |||||||||||||||
Operation and maintenance
|
6 | 655 | 1,026 | (196 | ) | 1,491 | ||||||||||||||
Depreciation, amortization and accretion
|
- | 112 | 396 | - | 508 | |||||||||||||||
Taxes other than on income
|
- | 274 | 168 | (5 | ) | 437 | ||||||||||||||
Other
|
- | (7 | ) | 38 | - | 31 | ||||||||||||||
Total operating expenses
|
6 | 2,834 | 2,962 | (201 | ) | 5,601 | ||||||||||||||
Operating (loss) income
|
(6 | ) | 811 | 767 | (3 | ) | 1,569 | |||||||||||||
Other income (expense)
|
||||||||||||||||||||
Interest income
|
- | 1 | 1 | - | 2 | |||||||||||||||
Allowance for equity funds used during construction
|
- | 24 | 53 | - | 77 | |||||||||||||||
Other, net
|
(59 | ) | 5 | (7 | ) | 1 | (60 | ) | ||||||||||||
Total other (expense) income, net
|
(59 | ) | 30 | 47 | 1 | 19 | ||||||||||||||
Interest charges
|
||||||||||||||||||||
Interest charges
|
216 | 204 | 149 | (1 | ) | 568 | ||||||||||||||
Allowance for borrowed funds used during construction
|
- | (11 | ) | (15 | ) | - | (26 | ) | ||||||||||||
Total interest charges, net
|
216 | 193 | 134 | (1 | ) | 542 | ||||||||||||||
(Loss) income from continuing operations before
income tax and equity in earnings of consolidated
subsidiaries
|
(281 | ) | 648 | 680 | (1 | ) | 1,046 | |||||||||||||
Income tax (benefit) expense
|
(100 | ) | 240 | 243 | 3 | 386 | ||||||||||||||
Equity in earnings of consolidated subsidiaries
|
832 | - | - | (832 | ) | - | ||||||||||||||
Income from continuing operations
|
651 | 408 | 437 | (836 | ) | 660 | ||||||||||||||
Discontinued operations, net of tax
|
- | (2 | ) | (2 | ) | - | (4 | ) | ||||||||||||
Net income
|
651 | 406 | 435 | (836 | ) | 656 | ||||||||||||||
Net income attributable to noncontrolling
interests, net of tax
|
- | (3 | ) | - | (2 | ) | (5 | ) | ||||||||||||
Net income attributable to controlling interests
|
$ | 651 | $ | 403 | $ | 435 | $ | (838 | ) | $ | 651 |
Condensed Consolidating Statement of Income
|
||||||||||||||||||||
Nine months ended September 30, 2010
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
Operating revenues
|
|
|
|
|
|
|||||||||||||||
Operating revenues
|
$ | - | $ | 4,075 | $ | 3,794 | $ | - | $ | 7,869 | ||||||||||
Affiliate revenues
|
- | - | 179 | (179 | ) | - | ||||||||||||||
Total operating revenues
|
- | 4,075 | 3,973 | (179 | ) | 7,869 | ||||||||||||||
Operating expenses
|
||||||||||||||||||||
Fuel used in electric generation
|
- | 1,252 | 1,322 | - | 2,574 | |||||||||||||||
Purchased power
|
- | 761 | 235 | - | 996 | |||||||||||||||
Operation and maintenance
|
5 | 647 | 977 | (170 | ) | 1,459 | ||||||||||||||
Depreciation, amortization and accretion
|
- | 311 | 369 | - | 680 | |||||||||||||||
Taxes other than on income
|
- | 278 | 175 | (5 | ) | 448 | ||||||||||||||
Other
|
- | 15 | 10 | - | 25 | |||||||||||||||
Total operating expenses
|
5 | 3,264 | 3,088 | (175 | ) | 6,182 | ||||||||||||||
Operating (loss) income
|
(5 | ) | 811 | 885 | (4 | ) | 1,687 | |||||||||||||
Other income (expense)
|
||||||||||||||||||||
Interest income
|
6 | 1 | 5 | (6 | ) | 6 | ||||||||||||||
Allowance for equity funds used during construction
|
- | 23 | 45 | - | 68 | |||||||||||||||
Other, net
|
(1 | ) | - | (7 | ) | 3 | (5 | ) | ||||||||||||
Total other income, net
|
5 | 24 | 43 | (3 | ) | 69 | ||||||||||||||
Interest charges
|
||||||||||||||||||||
Interest charges
|
214 | 219 | 159 | (5 | ) | 587 | ||||||||||||||
Allowance for borrowed funds used during construction
|
- | (10 | ) | (14 | ) | - | (24 | ) | ||||||||||||
Total interest charges, net
|
214 | 209 | 145 | (5 | ) | 563 | ||||||||||||||
(Loss) income from continuing operations before
income tax and equity in earnings of consolidated
subsidiaries
|
(214 | ) | 626 | 783 | (2 | ) | 1,193 | |||||||||||||
Income tax (benefit) expense
|
(83 | ) | 235 | 301 | 3 | 456 | ||||||||||||||
Equity in earnings of consolidated subsidiaries
|
861 | - | - | (861 | ) | - | ||||||||||||||
Income from continuing operations
|
730 | 391 | 482 | (866 | ) | 737 | ||||||||||||||
Discontinued operations, net of tax
|
1 | - | (3 | ) | - | (2 | ) | |||||||||||||
Net income
|
731 | 391 | 479 | (866 | ) | 735 | ||||||||||||||
Net (income) loss attributable to noncontrolling
interests, net of tax
|
- | (3 | ) | 1 | (2 | ) | (4 | ) | ||||||||||||
Net income attributable to controlling interests
|
$ | 731 | $ | 388 | $ | 480 | $ | (868 | ) | $ | 731 |
Condensed Consolidating Balance Sheet
|
||||||||||||||||||||
September 30, 2011
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
ASSETS
|
|
|
|
|
|
|||||||||||||||
Utility plant, net
|
$ | - | $ | 10,351 | $ | 11,578 | $ | 86 | $ | 22,015 | ||||||||||
Current assets
|
||||||||||||||||||||
Cash and cash equivalents
|
- | 34 | 69 | - | 103 | |||||||||||||||
Receivables, net
|
- | 630 | 577 | - | 1,207 | |||||||||||||||
Notes receivable from affiliated companies
|
97 | 27 | 138 | (262 | ) | - | ||||||||||||||
Regulatory assets
|
- | 128 | 52 | - | 180 | |||||||||||||||
Derivative collateral posted
|
- | 98 | 14 | - | 112 | |||||||||||||||
Prepayments and other current assets
|
131 | 816 | 1,062 | (186 | ) | 1,823 | ||||||||||||||
Total current assets
|
228 | 1,733 | 1,912 | (448 | ) | 3,425 | ||||||||||||||
Deferred debits and other assets
|
||||||||||||||||||||
Investment in consolidated subsidiaries
|
14,196 | - | - | (14,196 | ) | - | ||||||||||||||
Regulatory assets
|
- | 1,305 | 1,029 | (1 | ) | 2,333 | ||||||||||||||
Goodwill
|
- | - | - | 3,655 | 3,655 | |||||||||||||||
Nuclear decommissioning trust funds
|
- | 520 | 992 | - | 1,512 | |||||||||||||||
Other assets and deferred debits
|
94 | 215 | 907 | (479 | ) | 737 | ||||||||||||||
Total deferred debits and other assets
|
14,290 | 2,040 | 2,928 | (11,021 | ) | 8,237 | ||||||||||||||
Total assets
|
$ | 14,518 | $ | 14,124 | $ | 16,418 | $ | (11,383 | ) | $ | 33,677 | |||||||||
CAPITALIZATION AND LIABILITIES
|
||||||||||||||||||||
Equity
|
||||||||||||||||||||
Common stock equity
|
$ | 10,112 | $ | 4,874 | $ | 5,650 | $ | (10,524 | ) | $ | 10,112 | |||||||||
Noncontrolling interests
|
- | 3 | - | - | 3 | |||||||||||||||
Total equity
|
10,112 | 4,877 | 5,650 | (10,524 | ) | 10,115 | ||||||||||||||
Preferred stock of subsidiaries
|
- | 34 | 59 | - | 93 | |||||||||||||||
Long-term debt, affiliate
|
- | 309 | - | (36 | ) | 273 | ||||||||||||||
Long-term debt, net
|
3,542 | 4,482 | 3,693 | - | 11,717 | |||||||||||||||
Total capitalization
|
13,654 | 9,702 | 9,402 | (10,560 | ) | 22,198 | ||||||||||||||
Current liabilities
|
||||||||||||||||||||
Current portion of long-term debt
|
450 | - | 500 | - | 950 | |||||||||||||||
Short-term debt
|
45 | - | - | - | 45 | |||||||||||||||
Notes payable to affiliated companies
|
- | 259 | 3 | (262 | ) | - | ||||||||||||||
Derivative liabilities
|
35 | 175 | 93 | - | 303 | |||||||||||||||
Other current liabilities
|
318 | 1,015 | 1,104 | (187 | ) | 2,250 | ||||||||||||||
Total current liabilities
|
848 | 1,449 | 1,700 | (449 | ) | 3,548 | ||||||||||||||
Deferred credits and other liabilities
|
||||||||||||||||||||
Noncurrent income tax liabilities
|
- | 863 | 1,902 | (455 | ) | 2,310 | ||||||||||||||
Regulatory liabilities
|
- | 796 | 1,443 | 87 | 2,326 | |||||||||||||||
Other liabilities and deferred credits
|
16 | 1,314 | 1,971 | (6 | ) | 3,295 | ||||||||||||||
Total deferred credits and other liabilities
|
16 | 2,973 | 5,316 | (374 | ) | 7,931 | ||||||||||||||
Total capitalization and liabilities
|
$ | 14,518 | $ | 14,124 | $ | 16,418 | $ | (11,383 | ) | $ | 33,677 |
Condensed Consolidating Balance Sheet
|
||||||||||||||||||||
December 31, 2010
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
ASSETS
|
|
|
|
|
|
|||||||||||||||
Utility plant, net
|
$ | - | $ | 10,189 | $ | 10,961 | $ | 90 | $ | 21,240 | ||||||||||
Current assets
|
||||||||||||||||||||
Cash and cash equivalents
|
110 | 270 | 231 | - | 611 | |||||||||||||||
Receivables, net
|
- | 497 | 536 | - | 1,033 | |||||||||||||||
Notes receivable from affiliated companies
|
14 | 48 | 115 | (177 | ) | - | ||||||||||||||
Regulatory assets
|
- | 105 | 71 | - | 176 | |||||||||||||||
Derivative collateral posted
|
- | 140 | 24 | - | 164 | |||||||||||||||
Prepayments and other current assets
|
30 | 751 | 984 | (273 | ) | 1,492 | ||||||||||||||
Total current assets
|
154 | 1,811 | 1,961 | (450 | ) | 3,476 | ||||||||||||||
Deferred debits and other assets
|
||||||||||||||||||||
Investment in consolidated subsidiaries
|
14,316 | - | - | (14,316 | ) | - | ||||||||||||||
Regulatory assets
|
- | 1,387 | 987 | - | 2,374 | |||||||||||||||
Goodwill
|
- | - | - | 3,655 | 3,655 | |||||||||||||||
Nuclear decommissioning trust funds
|
- | 554 | 1,017 | - | 1,571 | |||||||||||||||
Other assets and deferred debits
|
75 | 238 | 894 | (469 | ) | 738 | ||||||||||||||
Total deferred debits and other assets
|
14,391 | 2,179 | 2,898 | (11,130 | ) | 8,338 | ||||||||||||||
Total assets
|
$ | 14,545 | $ | 14,179 | $ | 15,820 | $ | (11,490 | ) | $ | 33,054 | |||||||||
CAPITALIZATION AND LIABILITIES
|
||||||||||||||||||||
Equity
|
||||||||||||||||||||
Common stock equity
|
$ | 10,023 | $ | 4,957 | $ | 5,686 | $ | (10,643 | ) | $ | 10,023 | |||||||||
Noncontrolling interests
|
- | 4 | - | - | 4 | |||||||||||||||
Total equity
|
10,023 | 4,961 | 5,686 | (10,643 | ) | 10,027 | ||||||||||||||
Preferred stock of subsidiaries
|
- | 34 | 59 | - | 93 | |||||||||||||||
Long-term debt, affiliate
|
- | 309 | - | (36 | ) | 273 | ||||||||||||||
Long-term debt, net
|
3,989 | 4,182 | 3,693 | - | 11,864 | |||||||||||||||
Total capitalization
|
14,012 | 9,486 | 9,438 | (10,679 | ) | 22,257 | ||||||||||||||
Current liabilities
|
||||||||||||||||||||
Current portion of long-term debt
|
205 | 300 | - | - | 505 | |||||||||||||||
Notes payable to affiliated companies
|
- | 175 | 3 | (178 | ) | - | ||||||||||||||
Derivative liabilities
|
18 | 188 | 53 | - | 259 | |||||||||||||||
Other current liabilities
|
278 | 1,002 | 1,184 | (273 | ) | 2,191 | ||||||||||||||
Total current liabilities
|
501 | 1,665 | 1,240 | (451 | ) | 2,955 | ||||||||||||||
Deferred credits and other liabilities
|
||||||||||||||||||||
Noncurrent income tax liabilities
|
3 | 528 | 1,608 | (443 | ) | 1,696 | ||||||||||||||
Regulatory liabilities
|
- | 1,084 | 1,461 | 90 | 2,635 | |||||||||||||||
Other liabilities and deferred credits
|
29 | 1,416 | 2,073 | (7 | ) | 3,511 | ||||||||||||||
Total deferred credits and other liabilities
|
32 | 3,028 | 5,142 | (360 | ) | 7,842 | ||||||||||||||
Total capitalization and liabilities
|
$ | 14,545 | $ | 14,179 | $ | 15,820 | $ | (11,490 | ) | $ | 33,054 |
Condensed Consolidating Statement of Cash Flows
|
||||||||||||||||||||
Nine months ended September 30, 2011
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
Net cash provided by operating activities
|
$ | 659 | $ | 664 | $ | 909 | $ | (928 | ) | $ | 1,304 | |||||||||
Investing activities
|
||||||||||||||||||||
Gross property additions
|
- | (624 | ) | (911 | ) | - | (1,535 | ) | ||||||||||||
Nuclear fuel additions
|
- | (13 | ) | (121 | ) | - | (134 | ) | ||||||||||||
Purchases of available-for-sale securities and other
investments
|
- | (4,099 | ) | (437 | ) | - | (4,536 | ) | ||||||||||||
Proceeds from available-for-sale securities and other
investments
|
- | 4,101 | 408 | - | 4,509 | |||||||||||||||
Changes in advances to affiliated companies
|
(83 | ) | 22 | (23 | ) | 84 | - | |||||||||||||
Contributions to consolidated subsidiaries
|
(11 | ) | - | - | 11 | - | ||||||||||||||
Other investing activities
|
(6 | ) | 113 | 14 | - | 121 | ||||||||||||||
Net cash used by investing activities
|
(100 | ) | (500 | ) | (1,070 | ) | 95 | (1,575 | ) | |||||||||||
Financing activities
|
||||||||||||||||||||
Issuance of common stock, net
|
42 | - | - | - | 42 | |||||||||||||||
Dividends paid on common stock
|
(550 | ) | - | - | - | (550 | ) | |||||||||||||
Dividends paid to parent
|
- | (478 | ) | (450 | ) | 928 | - | |||||||||||||
Net increase in short-term debt
|
45 | - | - | - | 45 | |||||||||||||||
Proceeds from issuance of long-term debt, net
|
494 | 296 | 496 | - | 1,286 | |||||||||||||||
Retirement of long-term debt
|
(700 | ) | (300 | ) | - | - | (1,000 | ) | ||||||||||||
Changes in advances from affiliated companies
|
- | 84 | - | (84 | ) | - | ||||||||||||||
Contributions from parent
|
- | 10 | 1 | (11 | ) | - | ||||||||||||||
Other financing activities
|
- | (12 | ) | (48 | ) | - | (60 | ) | ||||||||||||
Net cash used by financing activities
|
(669 | ) | (400 | ) | (1 | ) | 833 | (237 | ) | |||||||||||
Net decrease in cash and cash equivalents
|
(110 | ) | (236 | ) | (162 | ) | - | (508 | ) | |||||||||||
Cash and cash equivalents at beginning of period
|
110 | 270 | 231 | - | 611 | |||||||||||||||
Cash and cash equivalents at end of period
|
$ | - | $ | 34 | $ | 69 | $ | - | $ | 103 |
Condensed Consolidating Statement of Cash Flows
|
||||||||||||||||||||
Nine months ended September 30, 2010
|
||||||||||||||||||||
(in millions)
|
Parent
|
Subsidiary
Guarantor
|
Non-
Guarantor
Subsidiaries
|
Other
|
Progress
Energy,
Inc.
|
|||||||||||||||
Net cash provided by operating activities
|
$ | 23 | $ | 872 | $ | 1,205 | $ | (196 | ) | $ | 1,904 | |||||||||
Investing activities
|
||||||||||||||||||||
Gross property additions
|
- | (775 | ) | (893 | ) | 25 | (1,643 | ) | ||||||||||||
Nuclear fuel additions
|
- | (32 | ) | (132 | ) | - | (164 | ) | ||||||||||||
Purchases of available-for-sale securities and other
investments
|
- | (5,461 | ) | (466 | ) | - | (5,927 | ) | ||||||||||||
Proceeds from available-for-sale securities and other
investments
|
- | 5,464 | 451 | - | 5,915 | |||||||||||||||
Changes in advances to affiliated companies
|
(24 | ) | (13 | ) | 242 | (205 | ) | - | ||||||||||||
Return of investment in consolidated subsidiaries
|
54 | - | - | (54 | ) | - | ||||||||||||||
Contributions to consolidated subsidiaries
|
(56 | ) | - | - | 56 | - | ||||||||||||||
Other investing activities
|
- | 16 | - | (1 | ) | 15 | ||||||||||||||
Net cash used by investing activities
|
(26 | ) | (801 | ) | (798 | ) | (179 | ) | (1,804 | ) | ||||||||||
Financing activities
|
||||||||||||||||||||
Issuance of common stock, net
|
419 | - | - | - | 419 | |||||||||||||||
Dividends paid on common stock
|
(535 | ) | - | - | - | (535 | ) | |||||||||||||
Dividends paid to parent
|
- | (102 | ) | (75 | ) | 177 | - | |||||||||||||
Dividends paid to parent in excess of retained earnings
|
- | - | (54 | ) | 54 | - | ||||||||||||||
Net decrease in short-term debt
|
(140 | ) | - | - | - | (140 | ) | |||||||||||||
Proceeds from issuance of long-term debt, net
|
- | 591 | - | - | 591 | |||||||||||||||
Retirement of long-term debt
|
(100 | ) | (300 | ) | - | - | (400 | ) | ||||||||||||
Changes in advances from affiliated companies
|
- | (205 | ) | - | 205 | - | ||||||||||||||
Contributions from parent
|
- | 33 | 37 | (70 | ) | - | ||||||||||||||
Other financing activities
|
- | (9 | ) | (69 | ) | 9 | (69 | ) | ||||||||||||
Net cash (used) provided by financing activities
|
(356 | ) | 8 | (161 | ) | 375 | (134 | ) | ||||||||||||
Net (decrease) increase in cash and cash equivalents
|
(359 | ) | 79 | 246 | - | (34 | ) | |||||||||||||
Cash and cash equivalents at beginning of period
|
606 | 72 | 47 | - | 725 | |||||||||||||||
Cash and cash equivalents at end of period
|
$ | 247 | $ | 151 | $ | 293 | $ | - | $ | 691 |
·
|
On August 23, 2011, the Merger was approved by the shareholders of Progress Energy and Duke Energy.
|
·
|
On March 28, 2011, Progress Energy and Duke Energy submitted their Hart-Scott-Rodino filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.
|
·
|
On July 27, 2011, the Federal Communications Commission approved the Assignment of Authorization filings to transfer control of certain licenses. The approval is effective for 180 days.
|
·
|
On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC’s acceptance of market power mitigation measures to address the FERC’s finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina power markets. Progress Energy and Duke Energy filed a market power mitigation plan with FERC on October 17, 2011. In the October 17, 2011 filing with the FERC, Progress Energy and Duke Energy proposed a “virtual divestiture” under which power up to a certain amount will be offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. In the proposal, after native loads have been met, power will be offered to entities serving load in the relevant areas at a price determined by the average incremental cost plus 10 percent. On a day-ahead order confirmation basis, PEC plans to offer 500 megawatt-hours (MWh) during each summer hour, which is less than 4 percent of PEC’s summer net capability. Duke Energy Carolinas plans to offer 300 MWh during each summer hour and 225 MWh during each winter hour. On October 31, 2011, Progress Energy and Duke Energy filed a request for a rehearing of the Merger order without withdrawing the previously submitted market power mitigation plan. In the request for rehearing, Progress Energy and Duke Energy asserted that the FERC had departed from its established merger rules in applying a more stringent analysis to assess whether the Merger will result in market power conditions in the Carolinas. We have requested that the FERC address the mitigation plan no later than December 15, 2011. If the FERC accepts the mitigation proposal, we will withdraw the request for a rehearing.
|
·
|
On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a Joint Dispatch Agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the Merger. The second filing is a joint open access transmission tariff pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate.
|
·
|
On March 30, 2011, Progress Energy and Duke Energy made filings with the NRC for approval for indirect transfer of control of licenses for Progress Energy’s nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses. The period to request a hearing or intervene expired in September 2011, and no such requests were received.
|
·
|
On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed the settlement with the South Carolina Office of Regulatory Staff, a party to the proceedings. If the settlement agreement is approved, Progress Energy and Duke Energy will guarantee $650 million in fuel cost savings for customers in North Carolina and South Carolina between 2012 and 2016, maintain their current level of community support for the next four years, and provide $15 million for low-income energy assistance and workforce development. The parties also agreed that direct merger-related expenses would not be recovered from customers. Recovery of merger-related employee severance costs can be requested separately. The NCUC held hearings regarding these applications on September 20-22, 2011, and proposed orders and/or briefs must be filed by November 14, 2011.
|
·
|
On April 25, 2011, Progress Energy and Duke Energy filed a merger-related filing and an application for approval of a Joint Dispatch Agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the merger-related filing as the merger of these entities is not likely to occur for several years after the close of the Merger. Hearings before the SCPSC to approve the joint dispatch agreement have been rescheduled for the week of December 12, 2011. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
|
·
|
On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy’s and Duke Energy’s merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky.
|
(in millions except per share data)
|
PEC
|
PEF
|
Corporate
and Other
|
Total
|
Per
Share
|
|||||||||||||||
Three months ended September 30, 2011
|
|
|
|
|
|
|||||||||||||||
Ongoing Earnings
|
$ | 202 | $ | 202 | $ | (60 | ) | $ | 344 | $ | 1.16 | |||||||||
Tax levelization
|
4 | 4 | - | 8 | 0.03 | |||||||||||||||
CVO mark-to-market, net of tax(a)
|
- | - | (50 | ) | (50 | ) | (0.17 | ) | ||||||||||||
Merger and integration costs, net of tax(a)
|
(8 | ) | (7 | ) | - | (15 | ) | (0.05 | ) | |||||||||||
CR3 indemnification adjustment, net of tax(a)
|
- | 4 | - | 4 | 0.01 | |||||||||||||||
Net income (loss) attributable to controlling interests(b)
|
$ | 198 | $ | 203 | $ | (110 | ) | $ | 291 | $ | 0.98 | |||||||||
Three months ended September 30, 2010
|
||||||||||||||||||||
Ongoing Earnings
|
$ | 233 | $ | 177 | $ | (49 | ) | $ | 361 | $ | 1.23 | |||||||||
Tax levelization
|
1 | 4 | (1 | ) | 4 | 0.01 | ||||||||||||||
Impairment, net of tax(a)
|
(1 | ) | (1 | ) | - | (2 | ) | (0.01 | ) | |||||||||||
Discontinued operations attributable to controlling
interests, net of tax
|
- | - | (2 | ) | (2 | ) | - | |||||||||||||
Net income (loss) attributable to controlling interests(b)
|
$ | 233 | $ | 180 | $ | (52 | ) | $ | 361 | $ | 1.23 | |||||||||
|
||||||||||||||||||||
Nine months ended September 30, 2011
|
||||||||||||||||||||
Ongoing Earnings
|
$ | 453 | $ | 454 | $ | (150 | ) | $ | 757 | $ | 2.56 | |||||||||
Tax levelization
|
1 | 2 | (1 | ) | 2 | 0.01 | ||||||||||||||
CVO mark-to-market, net of tax(a)
|
- | - | (46 | ) | (46 | ) | (0.15 | ) | ||||||||||||
Merger and integration costs, net of tax(a)
|
(19 | ) | (17 | ) | - | (36 | ) | (0.12 | ) | |||||||||||
CR3 indemnification charge, net of tax(a)
|
- | (22 | ) | - | (22 | ) | (0.08 | ) | ||||||||||||
Discontinued operations attributable to controlling
interests, net of tax
|
- | - | (4 | ) | (4 | ) | (0.02 | ) | ||||||||||||
Net income (loss) attributable to controlling interests(b)
|
$ | 435 | $ | 417 | $ | (201 | ) | $ | 651 | $ | 2.20 | |||||||||
Nine months ended September 30, 2010
|
||||||||||||||||||||
Ongoing Earnings
|
$ | 493 | $ | 409 | $ | (146 | ) | $ | 756 | $ | 2.61 | |||||||||
Tax levelization
|
4 | 2 | (3 | ) | 3 | 0.01 | ||||||||||||||
Impairment, net of tax(a)
|
(4 | ) | (1 | ) | - | (5 | ) | (0.01 | ) | |||||||||||
Plant retirement adjustment, net of tax(a)
|
1 | - | - | 1 | - | |||||||||||||||
Change in the tax treatment of the Medicare Part D subsidy
|
(12 | ) | (10 | ) | - | (22 | ) | (0.08 | ) | |||||||||||
Discontinued operations attributable to controlling
interests, net of tax
|
- | - | (2 | ) | (2 | ) | - | |||||||||||||
Net income (loss) attributable to controlling interests(b)
|
$ | 482 | $ | 400 | $ | (151 | ) | $ | 731 | $ | 2.53 |
(a)
|
Calculated using assumed tax rate of 40 percent to the extent items are tax deductible.
|
||||||||||||||
(b)
|
Net income attributable to controlling interests is shown net of preferred stock dividend requirement of $(1) million at PEC for the three months ended September 30, 2011 and 2010 and $(2) million for the nine months ended September 30, 2011 and 2010. Net income attributable to controlling interests is shown net of preferred stock dividend requirement of $(1) million at PEF for the nine months ended September 30, 2011 and 2010.
|
·
|
unrealized loss recorded due to mark-to-market change in fair value of contingent value obligations (CVOs) (Ongoing Earnings adjustment) and
|
·
|
retail disallowance of replacement power costs in 2011 resulting from the prior-year performance of nuclear plants at PEC.
|
·
|
less favorable impact of weather at the Utilities;
|
·
|
unrealized loss recorded due to mark-to-market change in fair value on CVOs (Ongoing Earnings adjustment); and
|
·
|
merger and integration costs related to the Merger (Ongoing Earnings adjustment).
|
·
|
lower depreciation and amortization expense at PEF.
|
(in millions)
|
|
|||||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
$ | 360 | $ | (25 | ) | (6.5 | ) | $ | 385 | |||||||
Commercial
|
205 | (9 | ) | (4.2 | ) | 214 | ||||||||||
Industrial
|
108 | (1 | ) | (0.9 | ) | 109 | ||||||||||
Governmental
|
20 | (2 | ) | (9.1 | ) | 22 | ||||||||||
Unbilled
|
2 | 25 |
NM
|
(23 | ) | |||||||||||
Total retail base revenues
|
695 | (12 | ) | (1.7 | ) | 707 | ||||||||||
Wholesale base revenues
|
74 | (10 | ) | (11.9 | ) | 84 | ||||||||||
Total Base Revenues
|
769 | (22 | ) | (2.8 | ) | 791 | ||||||||||
Clause-recoverable regulatory returns
|
8 | 4 | 100.0 | 4 | ||||||||||||
Miscellaneous
|
37 | - | - | 37 | ||||||||||||
Fuel and other pass-through revenues
|
518 | (64 | ) |
NM
|
582 | |||||||||||
Total operating revenues
|
$ | 1,332 | $ | (82 | ) | (5.8 | ) | $ | 1,414 | |||||||
NM - not meaningful
|
(in millions of kWh)
|
|
|
|
|
||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
5,134 | (366 | ) | (6.7 | ) | 5,500 | ||||||||||
Commercial
|
3,917 | (247 | ) | (5.9 | ) | 4,164 | ||||||||||
Industrial
|
2,870 | (69 | ) | (2.3 | ) | 2,939 | ||||||||||
Governmental
|
476 | 16 | 3.5 | 460 | ||||||||||||
Unbilled
|
(31 | ) | 480 |
NM
|
(511 | ) | ||||||||||
Total retail kWh sales
|
12,366 | (186 | ) | (1.5 | ) | 12,552 | ||||||||||
Wholesale
|
3,662 | (135 | ) | (3.6 | ) | 3,797 | ||||||||||
Total kWh sales
|
16,028 | (321 | ) | (2.0 | ) | 16,349 |
(in millions)
|
|
|||||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
$ | 940 | $ | (38 | ) | (3.9 | ) | $ | 978 | |||||||
Commercial
|
546 | (10 | ) | (1.8 | ) | 556 | ||||||||||
Industrial
|
279 | 1 | 0.4 | 278 | ||||||||||||
Governmental
|
50 | - | - | 50 | ||||||||||||
Unbilled
|
(26 | ) | (12 | ) |
NM
|
(14 | ) | |||||||||
Total retail base revenues
|
1,789 | (59 | ) | (3.2 | ) | 1,848 | ||||||||||
Wholesale base revenues
|
218 | (10 | ) | (4.4 | ) | 228 | ||||||||||
Total Base Revenues
|
2,007 | (69 | ) | (3.3 | ) | 2,076 | ||||||||||
Clause-recoverable regulatory returns
|
22 | 14 | 175.0 | 8 | ||||||||||||
Miscellaneous
|
100 | (2 | ) | (2.0 | ) | 102 | ||||||||||
Fuel and other pass-through revenues
|
1,396 | (212 | ) |
NM
|
1,608 | |||||||||||
Total operating revenues
|
$ | 3,525 | $ | (269 | ) | (7.1 | ) | $ | 3,794 |
(in millions of kWh)
|
|
|
|
|
||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
14,480 | (615 | ) | (4.1 | ) | 15,095 | ||||||||||
Commercial
|
10,644 | (277 | ) | (2.5 | ) | 10,921 | ||||||||||
Industrial
|
8,040 | (19 | ) | (0.2 | ) | 8,059 | ||||||||||
Governmental
|
1,236 | 32 | 2.7 | 1,204 | ||||||||||||
Unbilled
|
(626 | ) | (198 | ) |
NM
|
(428 | ) | |||||||||
Total retail kWh sales
|
33,774 | (1,077 | ) | (3.1 | ) | 34,851 | ||||||||||
Wholesale
|
9,840 | (926 | ) | (8.6 | ) | 10,766 | ||||||||||
Total kWh sales
|
43,614 | (2,003 | ) | (4.4 | ) | 45,617 |
(in millions)
|
|
|||||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
$ | 312 | $ | 1 | 0.3 | $ | 311 | |||||||||
Commercial
|
102 | - | - | 102 | ||||||||||||
Industrial
|
19 | (1 | ) | (5.0 | ) | 20 | ||||||||||
Governmental
|
24 | (1 | ) | (4.0 | ) | 25 | ||||||||||
Unbilled
|
(6 | ) | (2 | ) |
NM
|
(4 | ) | |||||||||
Total retail base revenues
|
451 | (3 | ) | (0.7 | ) | 454 | ||||||||||
Wholesale base revenues
|
30 | (11 | ) | (26.8 | ) | 41 | ||||||||||
Total Base Revenues
|
481 | (14 | ) | (2.8 | ) | 495 | ||||||||||
Clause-recoverable regulatory returns
|
46 | - | - | 46 | ||||||||||||
Miscellaneous
|
55 | (5 | ) | (8.3 | ) | 60 | ||||||||||
Fuel and other pass-through revenues
|
832 | (110 | ) |
NM
|
942 | |||||||||||
Total operating revenues
|
$ | 1,414 | $ | (129 | ) | (8.4 | ) | $ | 1,543 |
(in millions of kWh)
|
|
|
|
|
||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
6,181 | (1 | ) | - | 6,182 | |||||||||||
Commercial
|
3,459 | 4 | 0.1 | 3,455 | ||||||||||||
Industrial
|
838 | 2 | 0.2 | 836 | ||||||||||||
Governmental
|
869 | (24 | ) | (2.7 | ) | 893 | ||||||||||
Unbilled
|
(193 | ) | (70 | ) |
NM
|
(123 | ) | |||||||||
Total retail kWh sales
|
11,154 | (89 | ) | (0.8 | ) | 11,243 | ||||||||||
Wholesale
|
846 | (336 | ) | (28.4 | ) | 1,182 | ||||||||||
Total kWh sales
|
12,000 | (425 | ) | (3.4 | ) | 12,425 |
(in millions)
|
|
|||||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
$ | 771 | $ | (37 | ) | (4.6 | ) | $ | 808 | |||||||
Commercial
|
270 | - | - | 270 | ||||||||||||
Industrial
|
56 | (2 | ) | (3.4 | ) | 58 | ||||||||||
Governmental
|
68 | (1 | ) | (1.4 | ) | 69 | ||||||||||
Unbilled
|
6 | (18 | ) |
NM
|
24 | |||||||||||
Total retail base revenues
|
1,171 | (58 | ) | (4.7 | ) | 1,229 | ||||||||||
Wholesale base revenues
|
85 | (36 | ) | (29.8 | ) | 121 | ||||||||||
Total Base Revenues
|
1,256 | (94 | ) | (7.0 | ) | 1,350 | ||||||||||
Clause-recoverable regulatory returns
|
137 | 11 | 8.7 | 126 | ||||||||||||
Miscellaneous
|
162 | (5 | ) | (3.0 | ) | 167 | ||||||||||
Fuel and other pass-through revenues
|
2,084 | (338 | ) |
NM
|
2,422 | |||||||||||
Total operating revenues
|
$ | 3,639 | $ | (426 | ) | (10.5 | ) | $ | 4,065 |
(in millions of kWh)
|
|
|
|
|
||||||||||||
Customer Class
|
2011
|
Change
|
% Change
|
2010
|
||||||||||||
Residential
|
15,144 | (762 | ) | (4.8 | ) | 15,906 | ||||||||||
Commercial
|
9,037 | 46 | 0.5 | 8,991 | ||||||||||||
Industrial
|
2,459 | (12 | ) | (0.5 | ) | 2,471 | ||||||||||
Governmental
|
2,418 | (32 | ) | (1.3 | ) | 2,450 | ||||||||||
Unbilled
|
116 | (492 | ) |
NM
|
608 | |||||||||||
Total retail kWh sales
|
29,174 | (1,252 | ) | (4.1 | ) | 30,426 | ||||||||||
Wholesale
|
2,132 | (1,085 | ) | (33.7 | ) | 3,217 | ||||||||||
Total kWh sales
|
31,306 | (2,337 | ) | (6.9 | ) | 33,643 |
|
Three months ended September 30,
|
Nine months ended September 30,
|
||||||||||||||
(in millions)
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
Other interest expense
|
$ | (86 | ) | $ | (75 | ) | $ | (232 | ) | $ | (225 | ) | ||||
Other income tax benefit
|
30 | 30 | 89 | 88 | ||||||||||||
Other expense
|
(4 | ) | (4 | ) | (7 | ) | (9 | ) | ||||||||
Ongoing Earnings
|
(60 | ) | (49 | ) | (150 | ) | (146 | ) | ||||||||
Tax levelization
|
- | (1 | ) | (1 | ) | (3 | ) | |||||||||
CVO mark-to-market, net of tax
|
(50 | ) | - | (46 | ) | - | ||||||||||
Discontinued operations attributable to
controlling interests, net of tax
|
- | (2 | ) | (4 | ) | (2 | ) | |||||||||
Net loss attributable to controlling interests
|
$ | (110 | ) | $ | (52 | ) | $ | (201 | ) | $ | (151 | ) |
(in millions)
|
Replacement
Power Costs
|
Repair Costs
|
|||||||
Spent to date
|
$ | 457 | $ | 229 | |||||
NEIL proceeds received
|
(162 | ) | (136 | ) | |||||
Insurance receivable at September 30, 2011
|
(162 | ) | (48 | ) | |||||
Balance for recovery
|
$ | 133 |
(a)
|
$ | 45 |
(a)
|
As approved by the FPSC on January 1, 2011, PEF began collecting, subject to refund, replacement power costs related to CR3 within the fuel clause (See Note 7C in the 2010 Form 10-K). The replacement power costs to be recovered through the fuel clause during 2011 allow for full recovery of all of 2010’s and 2011’s replacement power costs. The 2011 fuel cost-recovery filing, discussed in “Fuel Cost Recovery,” anticipates full recovery of estimated 2012 replacement power costs.
|
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Cash Flow Hedges (dollars in millions)
|
Notional
Amount
|
Mandatory
Settlement
|
Pay
|
Receive (a)
|
Fair
Value
|
Exposure (b)
|
|||||||||||||||
Parent
|
|||||||||||||||||||||
Risk hedged at September 30, 2011
|
|||||||||||||||||||||
Anticipated 10-year debt issue
|
$ | 200 | 2012 | 4.20 | % |
3-month LIBOR
|
$ | (35 | ) | $ | (5 | ) | |||||||||
Risk hedged at December 31, 2010
|
|||||||||||||||||||||
Anticipated 10-year debt issue
|
$ | 300 | 2011 | 4.15 | % |
3-month LIBOR
|
$ | (18 | ) | $ | (7 | ) | |||||||||
Anticipated 10-year debt issue
|
$ | 200 | 2012 | 4.20 | % |
3-month LIBOR
|
$ | (3 | ) | $ | (4 | ) | |||||||||
PEC
|
|||||||||||||||||||||
Risk hedged at September 30, 2011
|
|||||||||||||||||||||
Anticipated 10-year debt issue
|
$ | 200 | 2012 | 4.27 | % |
3-month LIBOR
|
$ | (35 | ) | $ | (5 | ) | |||||||||
Anticipated 10-year debt issue
|
$ | 50 | 2013 | 4.43 | % |
3-month LIBOR
|
$ | (8 | ) | $ | (1 | ) | |||||||||
Risk hedged at December 31, 2010
|
|||||||||||||||||||||
Anticipated 10-year debt issue
|
$ | 100 | 2011 | 4.31 | % |
3-month LIBOR
|
$ | (7 | ) | $ | (2 | ) | |||||||||
Anticipated 10-year debt issue
|
$ | 200 | 2012 | 4.27 | % |
3-month LIBOR
|
$ | (2 | ) | $ | (4 | ) | |||||||||
Anticipated 10-year debt issue
|
$ | 50 | 2013 | 4.43 | % |
3-month LIBOR
|
$ | - | $ | (1 | ) | ||||||||||
PEF
|
|||||||||||||||||||||
Risk hedged at September 30, 2011
|
|||||||||||||||||||||
Anticipated 10-year debt issue
|
$ | 50 | 2013 | 4.30 | % |
3-month LIBOR
|
$ | (8 | ) | $ | (1 | ) | |||||||||
Risk hedged at December 31, 2010
|
|||||||||||||||||||||
Anticipated 10-year debt issue
|
$ | 150 | 2011 | 4.18 | % |
3-month LIBOR
|
$ | (6 | ) | $ | (3 | ) | |||||||||
Anticipated 10-year debt issue
|
$ | 50 | 2013 | 4.30 | % |
3-month LIBOR
|
$ | - | $ | (1 | ) | ||||||||||
(a)
|
3-month London Inter Bank Offered Rate (LIBOR) was 0.37% at September 30, 2011 and 0.30% at December 31, 2010.
|
(b)
|
Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.
|
ITEM 4. | CONTROLS AND PROCEDURES |
ITEM 1. | LEGAL PROCEEDINGS |
ITEM 1A. | RISK FACTORS |
ITEM 2. | UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS |
(a)
|
Securities Delivered. On July 25, 2011, and August 19, 2011, 3,300 shares and 6,700 shares, respectively, of our common stock were delivered to certain employees pursuant to the terms of the Progress Energy 2007 Equity Incentive Plan (the EIP) which has been approved by Progress Energy’s shareholders. Additionally, on July 26, 2011, 268 shares of our common stock were delivered to a former employee pursuant to the terms of the EIP. The shares of common stock delivered pursuant to the EIP were newly issued shares of Progress Energy.
|
(b)
|
Underwriters and Other Purchasers. No underwriters were used in connection with the delivery of our common stock described above.
|
(c)
|
Consideration. The restricted stock unit awards were granted to provide an incentive to the employees and the former employee to exert their utmost efforts on Progress Energy’s behalf and thus enhance our performance while aligning the employees’ interest with those of our shareholders.
|
(d)
|
Exemption from Registration Claimed. The common shares described in this Item were delivered pursuant to a broad-based involuntary, non-contributory employee benefit plan, and thus did not involve an offer to sell or sale of securities within the meaning of Section 2(3) of the Securities Act of 1933. Receipt of the shares of our common stock required no investment decision on the part of the recipient.
|
Period
|
(a)
Total
Number of
Shares
(or Units)
Purchased
(1)(2)(3)(4)(5)
|
(b)
Average
Price
Paid
Per
Share
(or Unit)
|
(c)
Total Number of
Shares (or Units) Purchased as Part
of Publicly
Announced Plans
or Programs
(1)
|
(d)
Maximum Number (or Approximate Dollar Value)
of Shares (or Units)
that May Yet Be
Purchased Under the
Plans or Programs
(1)
|
||||||||||||
July 1 – July 31
|
263,903 | $ | 47.7372 | N/A | N/A | |||||||||||
August 1 – August 31
|
725,507 | 46.1625 | N/A | N/A | ||||||||||||
September 1 – September 30
|
127,327 | 48.6933 | N/A | N/A | ||||||||||||
Total
|
1,116,737 | 46.8232 | N/A | N/A |
(1)
|
At September 30, 2011, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.
|
(2)
|
The plan administrator purchased 557,400 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy 401(k) Savings & Stock Ownership Plan.
|
(3)
|
The plan administrator purchased 311,679 shares of our common stock in open-market transactions to meet share delivery obligations under the Savings Plan for Employees of Florida Progress Corporation.
|
(4)
|
The plan administrator purchased 244,305 shares of our common stock in open-market transactions to meet share delivery obligations under the Progress Energy Investor Plus Plan.
|
(5)
|
Progress Energy withheld 3,353 shares of our common stock during the third quarter of 2011 to pay taxes due upon the payout of certain Restricted Stock Unit awards pursuant to the terms of the 2007 EIP.
|
ITEM 6. | EXHIBITS |
(a)
|
Exhibits
|
Exhibit Number
|
Description
|
Progress
Energy
|
PEC
|
PEF
|
*4(a)
|
Seventy-eighth Supplemental Indenture, dated as of September 1, 2011, to the Mortgage and Deed of Trust, dated May 1, 1940, as supplemented, between Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and The Bank of New York Mellon (formerly Irving Trust Company) and Frederick G. Herbst (Ming Ryan, successor), as trustees (filed as Exhibit 4 to the Current Report on Form 8-K, dated September 12, 2011, File No. 1-3382).
|
X
|
||
*4(b)
|
Fiftieth Supplemental Indenture, dated as of August 1, 2011, to the Indenture, dated January 1, 1944, as supplemented, between Florida Power Corporation d/b/a Progress Energy Florida, Inc. and The Bank of New York Mellon, as successor Trustee (filed as Exhibit 4 to the Current Report on Form 8-K, dated August 15, 2011, File No. 1-3274).
|
X
|
||
10(a)
|
Deferred Compensation Plan for Key Management Employees of Progress Energy, Inc., amended and restated effective July 13, 2011.
|
X
|
X
|
X
|
10(b)
|
Executive and Key Manager 2009 Performance Share Sub-Plan, Exhibit A to 2007 Equity Incentive Plan, amended and restated effective July 12, 2011.
|
X
|
X
|
X
|
10(c)
|
Amended Management Incentive Compensation Plan of Progress Energy, Inc., amended and restated effective July 12, 2011.
|
X
|
X
|
X
|
10(d)
|
Progress Energy, Inc. Management Change-in-Control Plan, amended and restated effective July 13, 2011.
|
X
|
X
|
X
|
10(e)
|
Progress Energy, Inc. Amended and Restated Management Deferred Compensation Plan, revised and restated effective July 12, 2011.
|
X
|
X
|
X
|
10(f)
|
Progress Energy, Inc. Non-Employee Director Deferred Compensation Plan, amended and restated effective July 13, 2011.
|
X
|
X
|
X
|
10(g)
|
Progress Energy, Inc. Non-Employee Director Stock Unit Plan, amended and restated effective July 13, 2011.
|
X
|
X
|
X
|
10(h)
|
Amended and Restated Progress Energy, Inc. Restoration Retirement Plan, amended and restated effective July 13, 2011.
|
X
|
X
|
X
|
10(i)
|
Amended and Restated Supplemental Senior Executive Retirement Plan of Progress Energy, Inc., amended and restated effective July 13, 2011.
|
X
|
X
|
X
|
31(a)
|
302 Certifications of Chief Executive Officer
|
X
|
||
31(b)
|
302 Certifications of Chief Financial Officer
|
X
|
||
31(c)
|
302 Certifications of Chief Executive Officer
|
X
|
||
31(d)
|
302 Certifications of Chief Financial Officer
|
X
|
||
31(e)
|
302 Certifications of Chief Executive Officer
|
X
|
||
31(f)
|
302 Certifications of Chief Financial Officer
|
X
|
||
32(a)
|
906 Certifications of Chief Executive Officer
|
X
|
||
32(b)
|
906 Certifications of Chief Financial Officer
|
X
|
||
32(c)
|
906 Certifications of Chief Executive Officer
|
X
|
||
32(d)
|
906 Certifications of Chief Financial Officer
|
X
|
||
32(e)
|
906 Certifications of Chief Executive Officer
|
X
|
||
32(f)
|
906 Certifications of Chief Financial Officer
|
X
|
||
101.INS
|
XBRL Instance Document**
|
X
|
X
|
X
|
101.SCH
|
XBRL Taxonomy Extension Schema Document
|
X
|
X
|
X
|
101.CAL
|
XBRL Taxonomy Calculation Linkbase Document
|
X
|
X
|
X
|
101.LAB
|
XBRL Taxonomy Label Linkbase Document
|
X
|
X
|
X
|
101.PRE
|
XBRL Taxonomy Presentation Linkbase Document
|
X
|
X
|
X
|
PROGRESS ENERGY, INC.
|
|
CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
|
|
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
|
|
Date: November 8, 2011
|
(Registrants)
|
By: /s/ Mark F. Mulhern
|
|
Mark F. Mulhern
|
|
Senior Vice President and Chief Financial Officer
|
|
By: /s/ Jeffrey M. Stone
|
|
Jeffrey M. Stone
|
|
Chief Accounting Officer and Controller
|
|
Progress Energy, Inc.
|
|
Chief Accounting Officer
|
|
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
|
|
Florida Power Corporation d/b/a Progress Energy Florida, Inc.
|
Page
|
|
ARTICLE 1 STATEMENT OF PURPOSE; EFFECTIVENESS
|
1
|
ARTICLE II DEFINITIONS
|
1
|
ARTICLE III ELIGIBILITY AND PARTICIPATION
|
5
|
ARTICLE IV RETIREMENT BENEFITS
|
6
|
ARTICLE V SURVIVOR BENEFITS
|
8
|
ARTICLE VI DISABILITY BENEFITS
|
9
|
ARTICLE VII SEVERANCE BENEFITS
|
10
|
ARTICLE VIII ADDITIONAL BENEFITS
|
11
|
ARTICLE IX ACCRUAL OF BENEFITS
|
12
|
ARTICLE X ADMINISTRATIVE COMMITTEE
|
12
|
ARTICLE XI AMENDMENT AND TERMINATION
|
13
|
ARTICLE XII MISCELLANEOUS
|
14
|
ARTICLE XIII CONSTRUCTION
|
17
|
|
(a)
|
the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or
|
|
(b)
|
the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or
|
|
(c)
|
the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or
|
|
(d)
|
the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board of Directors; or
|
|
(e)
|
the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor’s assets; or
|
|
(f)
|
the date of any event which the Board of Directors determines should constitute a Change of Control.
|
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
ATTEST:
/s/ Holly H. Wenger
Holly H. Wenger
Assistant Secretary
[Corporate Seal]
|
1.1
|
“Account” means the account used to record and track the number of Performance Shares granted to each Participant as provided in Section 2.4.
|
1.2
|
“Award” as used in this Sub-Plan means each aggregate award of Performance Shares as provided in Section 2.2.
|
1.3
|
“Change of Control” means a change of control as defined for purposes of Section 409A of the Code.
|
1.4
|
“Disability” means disability as defined for purposes of Section 409A of the Code.
|
1.5
|
“Early Retirement” means Separation from Service after attaining age 55 and completing at least 10 years of service.
|
1.6
|
“Early Vesting Event” with respect to a Performance Award means the Participant’s death, Disability, Retirement, or Separation from Service as a result of a Divestiture, or any of the vesting events provided in Section 3.2 in connection with a Change in Control.
|
1.7
|
“Earnings Growth” means the average rate of growth in the on-going earnings per share of the Company Stock during the Performance Period as determined by the Committee from time to time.
|
1.8
|
“Normal Retirement” means Separation from Service on or after attaining age 65.
|
1.9
|
“Peer Group” means the peer group of utilities designated by the Committee prior to the beginning of the Performance Period for which an Award is granted.
|
1.10
|
“Performance Period” for purposes of this Sub-Plan means three consecutive Years beginning with the Year in which an Award is granted.
|
1.11
|
“Performance Schedule” means Attachment 1 to this Sub-Plan, which sets forth the methodology for calculating the Performance Share Awards applicable to this Sub-Plan.
|
1.12
|
“Performance Share” for purposes of this Sub-Plan means each unit of an Award granted to a Participant, the value of which is equal to the value of Company Stock as hereinafter provided.
|
1.13
|
“Retire” or “Retirement” means Early Retirement or Normal Retirement.
|
1.14
|
“Salary” means the regular base rate of compensation payable by the Company to a Participant on an annual basis. Salary does not include bonuses, if any, or incentive compensation, if any. Such compensation shall not be reduced by any deferrals made under any other plans or programs maintained by the Company.
|
1.15
|
“Section 409A” means Section 409A of the Code, or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time.
|
1.16
|
“Separation from Service” means separation from service with the Company as defined for purposes of Section 409A of the Code.
|
1.17
|
“Total Shareholder Return” means the average annual percentage return realized by the owner of a share of Company Stock for each Year during a relevant Performance Period. The annual percentage return is equal to the appreciation or depreciation in value of a share of Company Stock (which is equal to the average of the daily opening and closing value of the stock over the last thirty trading days of the relevant period minus the average of the daily opening and closing value of the stock over the last thirty trading days of the preceding Year) plus the dividends paid on such share during the relevant period, divided by the average of the daily opening and closing value of the stock over the last thirty trading days of the preceding Year.
|
1.18
|
“Year” means a calendar year.
|
|
Section 2. Sub-Plan Participation and Awards
|
Participant
|
Target Award
|
Maximum Award
|
CEO*
|
233% of Salary
|
291.25% of Salary
|
COO*
|
184% of Salary
|
230% of Salary
|
CFO*
|
133% of Salary
|
166.25% of Salary
|
Presidents*/Executive VPs*
|
117% of Salary
|
146.25% of Salary
|
Senior VPs*
|
100% of Salary
|
125% of Salary
|
VP/Department Heads**
Level I
Level II
|
80% of Salary
67% of Salary
|
100% of Salary
83.75% of Salary
|
Key Managers
|
67% of Salary
|
83.75% of Salary
|
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
|
ATTACHMENT 1
|
|
PERFORMANCE SCHEDULE
|
|
PERFORMANCE SHARE CALCULATION
|
|
for Post-2008 Performance Awards
|
Ranking of Total
Shareholder
Return Relative to
Peer Group
|
Less than
40th
Percentile
|
40th
Percentile
|
50th
Percentile
|
80th or
Higher
Percentile
|
Vested % of
Target Award
Earned
|
0%
|
50%
|
100%
|
200%
|
Rate of Earnings
Growth
|
Less than 2%
|
2%
|
4%
|
6% or Higher
|
Vested % of Target
Award Earned
|
0%
|
50%
|
100%
|
200%
|
[ ]
|
100% of the Award
|
[ ]
|
50% of the Award
|
||||||
[ ]
|
75% of the Award
|
[ ]
|
25% of the Award
|
[ ]
|
a specific date certain at least 5 years from expiration
of the Performance Period:
|
______4/1/_____
(month/day/year)
|
||
[ ]
|
the April 1 following the date of Retirement, or if later, the date which is six months after the date of my Separation from Service for any reason (including Retirement), if I am a “key employee” as defined in Section 416(i) of the Code (but determined without regard to paragraph 5 thereof or the 50 employee limit on the number of officers treated as key employees). | |||
[ ]
|
the April 1 following the first anniversary of my date of Retirement
|
[ ]
|
a single payment
|
|
[ ]
|
annual payments commencing on the date set forth above and payable on the anniversary date thereof over:
|
[ ]
|
a two year period
|
[ ]
|
a three year period
|
|||||
[ ]
|
a four year period
|
[ ]
|
a five year period
|
(Signature)
|
(Date)
|
|
(Print Name)
|
(Company Location)
|
|
Received:
Agent of Chief Executive Officer
|
||
(Signature)
|
(Date)
|
Page
|
||
ARTICLE I
|
PURPOSE
|
1
|
ARTICLE II
|
DEFINITIONS
|
1
|
ARTICLE III
|
ADMINISTRATION
|
9
|
ARTICLE IV
|
PARTICIPATION
|
9
|
ARTICLE V
|
AWARDS
|
10
|
ARTICLE VI
|
DISTRIBUTION AND DEFERRAL OF AWARDS
|
12
|
ARTICLE VII
|
TERMINATIN OF EMPLOYMENT
|
19
|
ARTICLE VIII
|
MISCELLANEOUS
|
19
|
EXHIBIT A
|
MICP RELATIVE PERFORMANCE WEIGHTINGS
|
|
EXHIBIT B
|
MANAGEMENT INCENTIVE EXAMPLE
|
|
EXHIBIT C
|
PARTICIPATING EMPLOYERS
|
|
FORM OF DESIGNATION OF BENEFICIARY
|
(a)
|
embezzlement or theft from the Company, or other acts of dishonesty, disloyalty or otherwise injurious to the Company;
|
(b)
|
disclosing without authorization proprietary or confidential information of the Company;
|
(c)
|
committing any act of negligence or malfeasance causing injury to the Company;
|
(d)
|
conviction of a crime amounting to a felony under the laws of the United States or any of the several states;
|
(e)
|
any violation of the Company’s Code of Ethics; or
|
(f)
|
unacceptable job performance which has been substantiated in accordance with the normal practices and procedures of the Company.
|
(a)
|
the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or
|
(b)
|
the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or
|
(c)
|
the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or
|
(d)
|
the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or
|
(e)
|
the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or
|
|
disposition by the Sponsor of all or substantially all of the Sponsor’s assets; or
|
(f)
|
the date of any event which the Board determines should constitute a Change in Control.
|
Participation
|
Target Award Opportunities
|
Chief Executive Officer of Sponsor*
|
85%
|
Chief Operating Officer of Sponsor*
|
70%
|
Presidents*/Executive Vice Presidents*
|
55%
|
Senior Vice Presidents*
|
45%
|
Department Heads
|
35%
|
Other Participants:
Key Managers
Other Managers
Supervisory Personnel
|
25% and 30%
20%
10%, 12%, and 15%
|
Performance Level
|
Payout Percentage
|
|||
Outstanding
|
200%
|
|||
Target
|
100%
|
|||
Threshold
|
50%
|
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
POSITION
|
COMPANY
EPS
|
LEGAL
ENTITY
EARNINGS
|
ECIP
GOALS
|
SMC – CEO
|
100%
|
–
|
–
|
SMC – COO
|
45%
|
55%
|
–
|
SMC – Presidents
|
45%
|
55%
|
–
|
SMC – Service Company CEO
|
100%
|
–
|
–
|
SMC – Non Service Company
|
35%
|
65%
|
–
|
SMC – Service Company
|
100%
|
–
|
–
|
Non Service Company Department Heads and Managers
|
50%
|
50%
|
–
|
Service Company Department Heads and Managers
|
50%
|
50%
|
–
|
Note:
|
This structure may be modified from time to time as provided in Section 2 of Article V of the Plan. The Compensation Committee may consider ECIP Goals achievement in determining any reduction of Awards of Participants who are members of the Senior Management Committee. In addition, the CEO may consider ECIP Goals achievement in determining any reduction of Awards for all other Participants.
|
MANAGEMENT INCENTIVE EXAMPLE
|
||||||||||
(Assumes preliminary PDP and Succession Planning rates are complete)
|
||||||||||
Step 1: Calculate achievement factor
for members of a department
|
||||||||||
Achievement
Level
|
Achievement
Percentage
|
Weighting
(see Pro Rate %)
|
Achievement
Factor
|
|||||||
PGN EPS
|
Target
|
100%
|
50.0%
|
50.0%
|
||||||
Legal Entity Earnings
|
Outstanding
|
200%
|
50.0%
|
100.0%
|
||||||
Total achievement factor
|
150.0% Would be calculated for each BU
|
|||||||||
Step 2: Apply achievement factor to target levels
|
||||||||||
Target
%
|
Achievement
Factor
|
Initial
Payout %
|
||||||||
Department Head
|
35.0%
|
150.0%
|
52.5%
|
|||||||
Other Section Manager
Section Manager
|
30.0%
25.0%
|
150.0%
150.0%
|
45.0%
37.5%
|
|||||||
Unit Manager
|
20.0%
|
150.0%
|
30.0%
|
|||||||
Supervisor
|
15.0%
|
150.0%
|
22.5%
|
|||||||
Step 3: Determine dollars eligible by department:
|
||||||||||
Salary
|
Target
%
|
Initial
Payout %
|
Calculated
Award
|
|||||||
John Doe, Department Head
|
200,000
|
35.0%
|
52.5%
|
$105,000
|
||||||
John Que, Other Section Manager
Jane Doe, Section Manager
|
100,000
100,000
|
30.0%
25.0%
|
45.0%
37.5%
|
45,000
37,500
|
||||||
John Smith, Section Manager
|
120,000
|
25.0%
|
37.5%
|
45,000
|
||||||
Jane Smith, Unit Manager
|
80,000
|
20.0%
|
30.0%
|
24,000
|
||||||
John Jones, Unit Manager
|
75,000
|
20.0%
|
30.0%
|
22,500
|
||||||
Jane Jones, Supervisor
|
90,000
|
15.0%
|
22.5%
|
20,250
|
||||||
$299,250
|
||||||||||
Step 4: Provide each group executive a list of their departments and calculated award totals.
Allow them to redistribute dollars based on organization performance within group.
|
||||||||||
Step 5: Allocate dollars by group and department:
|
||||||||||
Salary
|
Target
%
|
Initial
Payout %
|
Calculated
Award
|
Discretionary
Adjustment
|
Actual
Award
|
Award
%
|
||||
John Doe
|
200,000
|
35.0%
|
52.5%
|
$105,000
|
($12,600)
|
$92,400
|
46.2%
|
|||
John Que,
Jane Doe
|
100,000
100,000
|
30.0%
25.0%
|
45.0%
37.5%
|
45,000
37,500
|
0
5,000
|
45,000
42,500
|
45.0%
42.5%
|
|||
John Smith
|
120,000
|
25.0%
|
37.5%
|
45,000
|
(3,000)
|
42,000
|
35%
|
|||
Jane Smith
|
80,000
|
20.0%
|
30.0%
|
24,000
|
-
|
24,000
|
30%
|
|||
John Jones
|
75,000
|
20.0%
|
30.0%
|
22,500
|
5,000
|
27,500
|
36.7%
|
|||
Jane Jones
|
90,000
|
15.0%
|
22.5%
|
20,250
|
(3,050)
|
17,200
|
19.11%
|
|||
$299,250
|
$290,600
|
|||||||||
Per group executive, department total to spend is $245,600
|
||||||||||
(Step 4)
|
||||||||||
General notes:
|
||||||||||
The departmental sheets would still be rolled into group level sheets and reviewed by level as in prior years (all dh’s together, 25% participants, 20% participants, 10% participants, 12% participants, and15% participants)
Discretion based on PDP (core skills and performance goals) , succession planning ratings, and ECIP Goals achievement
Discretionary percentage should reflect a range of +/- TBD% of payout % for group
Steps 1 & 2 (MICP) fund determination) based on legal entities. Steps 3-5 (MICP allocation) utilize reporting organization/group.
|
|
1.0
|
PURPOSE OF PLAN
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1.1
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Purpose. The purpose of the Progress Energy, Inc. Management Change-in-Control Plan (the “Plan”) is to attract and retain certain highly qualified individuals as management employees of Progress Energy, Inc. and its subsidiaries, and to provide a benefit to such management employees if their employment is terminated in connection with a Change in Control (as defined below). This Plan is intended to qualify as a “top-hat” plan under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), in that it is intended to be an “employee pension benefit plan” (as such term is defined under Section 3(2) of ERISA) which is unfunded and provides benefits only to a select group of management or highly compensated employees of the Company or any Subsidiary. The Plan amends and restates the Plan as restated effective July 10, 2002, January 1, 2005, January 1, 2007, and January 1, 2008. The Carolina Power & Light Company Management Change-in-Control Plan was originally adopted effective January 1, 1998.
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2.0
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DEFINITIONS
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2.1
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“Beneficiary” shall mean a beneficiary designated in writing by a Participant to receive any payments to be made under the Plan to such Participant, and if no beneficiary is designated by the Participant, then the Participant’s estate shall be deemed to be the Participant’s designated beneficiary.
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2.2
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“Board” shall mean the Board of Directors of the Company.
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2.3
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“Cash Payment” shall mean a payment in cash by the Company or any Subsidiary to a Participant in accordance with Section 6.1 below.
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2.4
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“Cause” shall mean:
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(a)
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embezzlement or theft from the Company or any Subsidiary, or other acts of dishonesty, disloyalty or otherwise injurious to the Company or any Subsidiary;
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(b)
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disclosing without authorization proprietary or confidential information of the Company or any Subsidiary;
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(c)
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committing any act of negligence or malfeasance causing injury to the Company or any Subsidiary;
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(d)
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conviction of a crime amounting to a felony under the laws of the United States or any of the several states;
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2.5
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“Change-in-Control” shall be deemed to have occurred on the earliest of the following dates:
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(a)
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the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Company, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Company representing twenty-five percent (25%) or more of the combined voting power of the Company’s then outstanding securities (excluding the acquisition of securities of the Company by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Company); or
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(b)
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the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Company’s then outstanding voting securities; or
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(c)
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the date of consummation of a merger, share exchange or consolidation of the Company with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Company or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or
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(d)
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the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Company (other than such an offer by the Company for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or
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(e)
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the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets; or
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(f)
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the date of any event which the Board determines should constitute a Change-in-Control.
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2.6
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“Change-in-Control Benefits” shall mean the benefits described under Section 6 below provided to Terminated Participants. Except as otherwise provided herein, a Terminated Participant who is terminated in anticipation of a Change-in-Control as described in Section 5.1 shall be entitled to receive the Change-in-Control Benefits as of the Termination Date notwithstanding the fact that the anticipated Change-in-Control does not occur.
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2.7
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“Change-in-Control Date” shall mean the date that a Change-in-Control first occurs.
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2.8
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“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.
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2.9
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“Committee” shall mean (i) the Board or (ii) a committee or subcommittee of the Board appointed by the Board from among its members. The Committee shall be the Board’s Committee on Organization and Compensation until a different Committee is appointed. On a Change-in-Control Date, and during the 36-month period following such Change-in-Control Date, the Committee shall be comprised of such persons as appointed by the Board prior to the Change-in-Control Date, with any additions or changes to the Committee following such Change-in-Control Date, with any additions or changes to the Committee following such Change-in-Control Date to be made and or approved by all Committee members then in office.
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Effective as of the Effective Time as such term is defined in the Agreement and Plan of Merger by and among Duke Energy Corporation, Diamond Acquisition Corporation and the Company dated as of January 8, 2011, “Committee” shall mean (i) the Board or (ii) a committee or subcommittee of the Board appointed by the Board from among its members. The Committee shall be the Board’s Committee on Organization and Compensation until a different Committee is appointed.
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2.10
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“Company” shall mean Progress Energy, Inc., a North Carolina corporation, including any successor entity or any successor to the assets of the Company that has assumed the Plan.
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2.11
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“Continuing Directors” shall mean the members of the Board as of the Effective Date; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.
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2.12
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“Effective Date” of the Plan, as amended and restated herein, shall mean January 1, 2008.
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2.13
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“Good Reason” shall mean the occurrence of any of the following:
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(a)
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a reduction in the Participant’s base salary without the Participant’s prior written consent (other than any reduction applicable to management employees generally);
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(b)
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a material adverse change in the Participant’s position, duties or responsibilities with respect to his or her employment with the Company and/or any Subsidiary without the Participant’s prior written consent;
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(c)
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a material reduction in the Participant’s total incentive compensation opportunity under the Company’s Management Incentive Compensation Plan, the 1997 Equity Incentive Plan, the 2002 Equity Incentive Plan, the 2007 Equity Incentive Plan, the
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Performance Share Sub-Plans, or any other incentive compensation plan (based on the total incentive compensation opportunity previously granted to such Participant during the 12-month period preceding a Change-in-Control Date) without the Participant’s prior written consent;
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(d)
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an actual change in the Participant’s principal work location by more than 50 miles and more than 50 miles from the Participant’s principal place of abode as of the date of such change in job location without the Participant’s prior written consent;
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(e)
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the failure of the Company to obtain the assumption of its obligation under the Plan by any successor to all or substantially all of the assets of the Company within 30 days after a merger, consolidation, sale or similar transaction constituting a Change-in-Control; or
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(f)
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a material breach by the Company of any term or provision of the Plan without the Participant’s prior written consent.
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Effective January 8, 2011, notwithstanding the preceding provisions of this Section 2.13, with respect to “Post-Agreement Awards” (as defined below), the term “Good Reason” shall be defined as follows:
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“Good reason” shall mean (i) a material reduction in the Participant’s annual base salary as in effect immediately before the Effective Time as defined in the Agreement and Plan of Merger between the Company and Duke Energy Corporation (exclusive of any across the board reduction similarly affecting all or substantially all similarly situated employees determined without regard to whether or not an otherwise similarly situated employee’s employment was with the Company prior to the Effective Time) or (ii) a material reduction in the Participant’s target annual bonus as in effect immediately prior to the Effective Time (exclusive of any across the board reduction similarly affecting all or substantially all similarly situated employees determined without regard to whether or not an otherwise similarly situated employee’s employment was with the Company prior to the Effective Time).
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The term “Post-Agreement Award” means any equity award, including but not limited to options, restricted stock, restricted stock units and performance shares granted by the Company on or after January 8, 2011, other than any such awards granted to a Participant who has signed an agreement, with the Company or another entity, waiving the Participant’s right to assert certain grounds for a resignation with Good Reason (as defined in clauses (a) through (f) above).
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2.14
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“Gross-Up Payment” shall mean a payment described in Section 11 below.
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2.15
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“Management Employee” shall mean a regular full-time employee of the Company or any Subsidiary with managerial duties and responsibilities.
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2.16
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“Participant” shall mean any Management Employee who has been designated to participate in the Plan under Section 3 below.
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2.17
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"Plan” shall mean the Progress Energy, Inc. Management Change-in-Control Plan.
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2.18
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“Retirement” shall mean the termination of employment of a Participant after having
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attained the age of 65 with five or more years of service, or the age of 55 with 15 or more years of service, or after having completed 35 or more years of service regardless of age.
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2.19
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“Section 409A” shall mean Section 409A of the Code, or any successor section under the Code, as amended and as interpreted by final or proposed regulations promulgated thereunder from time to time and by related guidance.
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2.20
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“Separation from Service” shall mean the death, Retirement or other termination of employment with the Company as defined for purposes of Section 409A.
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2.21
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“Specified Employee” shall mean a “key employee,” as defined in Section 416(i) of the Code without regard to paragraph 5 thereof or the 50-employee limit on the number of officers treated as key employees.
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2.22
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“Subsidiary” shall mean a corporation of which the Company directly or indirectly owns more than fifty percent (50%) of the voting stock (meaning the capital stock of any class or classes having general voting power under ordinary circumstances, in the absence of contingencies, to elect the directors of a corporation) or any other business entity in which the Company directly or indirectly has an ownership interest of more than 50 percent.
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2.23
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“Terminated Participant” shall mean a Participant whose employment is terminated as described in Section 5 below; provided, however, that a Participant who is reemployed by the Company or any Subsidiary without an intervening break in service shall not be a Terminated Participant for purposes of this Plan.
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2.24
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“Termination Date” shall mean the date a Terminated Participant’s employment with the Company and/or a Subsidiary is terminated as described in Section 5 below.
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2.25
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“Trigger Trust” shall mean a trust as described in Section 8 below.
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3.0
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ELIGIBILITY AND PARTICIPATION
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(a)
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Tier I -
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Chief Executive Officer, Chief Operating Officer, President and Executive Vice Presidents who are members of the Senior Management Committee of the Company.
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(b)
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Tier II -
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Senior Vice Presidents who are members of the Senior Management Committee of the Company.
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(c)
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Tier III -
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Vice Presidents, Department Heads and other selected Management Employees of the Company or any Subsidiary.
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3.2
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Participation. The Committee shall designate each eligible Management Employee who is a Participant in the Plan. The Committee may, in its sole discretion, terminate the participation of a Participant at any time prior to the date that substantive negotiations occur in connection with a potential Change-in-Control.
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4.0
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ADMINISTRATION
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4.1
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Responsibility. The Committee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms.
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4.2
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Authority of the Committee. The Committee shall have the maximum discretionary authority permitted by law that may be necessary to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following:
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(a)
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to determine eligibility for participation in the Plan;
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(c)
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to determine and establish the formula to be used in calculating a Participant’s Change-in-Control Benefits;
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(d)
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to correct any defect, supply any omission, or reconcile any inconsistency in the Plan in such manner and to such extent as it shall deem appropriate in its sole discretion to carry the same into effect;
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(e)
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to issue administrative guidelines as an aid to administer the Plan and make changes in such guidelines as it from time to time deems proper;
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(f)
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to make rules for carrying out and administering the Plan and make changes in such rules as it from time to time deems proper;
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(g)
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to the extent permitted under the Plan, grant waivers of Plan terms, conditions, restrictions, and limitations;
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(h)
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to make reasonable determinations as to a Participant’s eligibility for benefits under the Plan, including determinations as to Cause and Good Reason; and
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(i)
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to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan.
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4.3
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Action by the Committee. The Committee may act only by a majority of its members. Any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee.
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4.4
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Delegation of Authority. The Committee may delegate to one or more of its members, or to one or more agents, such administrative duties as it may deem advisable; provided, however, that any such delegation shall be in writing. In addition, the Committee, or any person to whom it has delegated duties as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid by the Company, or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee.
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4.5
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Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive to the maximum extent permitted by law on all Participants and their heirs, successors, and legal representatives.
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4.6
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Information. The Company shall furnish to the Committee in writing all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. Such information may include, but shall not be limited to, the full names of all Participants, their earnings and their dates of birth, employment, retirement or death. Such information shall be conclusive for all purposes of the Plan, and the Committee shall be entitled to rely thereon without any investigation thereof.
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4.7
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Self-Interest. No member of the Committee may act, vote or otherwise influence a decision of the Committee specifically relating to his or her benefits, if any, under the Plan.
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5.0
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TERMINATION OF EMPLOYMENT
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5.1
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Termination of Employment. If the Company or a Subsidiary employing a Participant terminates such Participant’s employment without Cause, or if a Participant terminates his or her employment with the Company or a Subsidiary for Good Reason, and in either case such termination of employment is a Separation from Service that is not due to the death or Retirement of the Participant, and such termination of employment occurs during the 24-month period following the Change-in-Control Date, or occurs prior to the Change-in-Control Date but after substantive negotiations leading to the Change-in-Control and can be demonstrated to have occurred at the request or initiation of parties to the Change-in-Control (such date of termination of employment shall be referred to herein as the “Termination Date”), the Terminated Participant shall be entitled to receive the Change-in-Control Benefits in accordance with Section 6 below.
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6.0
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CHANGE-IN-CONTROL BENEFITS
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6.1
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Cash Payment. Within ten days following the Termination Date, the Company shall pay to the Terminated Participant, in a lump sum, an amount in cash as determined under a formula established by the Committee (such formula to be established by the Committee, in its sole discretion, on the date the Committee designates such individual as a Participant in accordance with Section 3.2 above); provided, however, that such Cash Payment shall not exceed in the aggregate an amount equal to the sum of:
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(a)
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The Applicable Percentage of the Terminated Participant’s annual base salary in effect on the Termination Date; plus
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(b)
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The Applicable Percentage of the greater of (i) the average of the Terminated Participant’s annual incentive bonus paid to the Terminated Participant under the Company’s Management Incentive Compensation Plan or otherwise with respect to the three completed calendar years immediately preceding the year in which the Termination Date occurs; provided, however, that if the Terminated Participant was not eligible to receive an annual incentive bonus with respect to each of the three calendar years immediately preceding the year in which the Termination Date occurs, the average shall be determined for that period of calendar years, if any, for which the Terminated Participant was eligible to receive an annual incentive bonus,
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or (ii) the Terminated Participant’s target annual incentive bonus for the year in which the Termination Date occurs.
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Participant
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Applicable Percentage
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Tier I
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300%
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Tier II
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200%
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Tier III
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150%
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6.2
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Annual Cash Incentive Compensation Plans. The Terminated Participant shall be entitled to receive an amount equal to his or her compensation under the annual cash incentive compensation plan covering the Terminated Participant based on 100 percent (100%) of his or her target bonus under such plan, which shall be paid during the 10-day period following the Termination Date.
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6.3
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Long Term Compensation Plan. The Terminated Participant shall be entitled to receive any awards which have been earned prior to the Termination Date under the Company’s Amended and Restated Long Term Compensation Plan, which shall be paid during the 10-day period following the Termination Date.
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6.4
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Restricted Stock Agreements. The Terminated Participant shall become vested as of the Termination Date in any restricted share awards which have been granted to him or her under the Company’s 1997 Equity Incentive Plan, the 2002 Equity Incentive Plan or any successor plans, and such shares shall be delivered to him or her without restriction during the 10-day period following the Termination Date.
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6.5
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Performance Share Sub-Plans. The Terminated Participant shall become vested as of the Termination Date in any awards which have been granted to such Participant under the Company’s Performance Share Sub-Plans. The Terminated Participant shall be entitled to payment of any awards which have been granted to him or her under such plans prior to the Termination Date within 60-90 days following the Termination Date.
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6.6
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Stock Option Agreements. Except to the extent that greater rights are provided to the Terminated Participant under the terms of a Stock Option Agreement between the Terminated Participant and the Company, the Terminated Participant shall have the following rights under any Stock Option Agreement following the Termination Date:
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(a)
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Option Assumed by Successor. If the Stock Option Agreement has been assumed by the successor to the Company on or before the Change-in-Control Date, any options not previously forfeited shall vest in accordance with the terms of the Stock Option Agreement and any vested options may be exercised by the Terminated Participant during the remaining term of such options notwithstanding the termination of employment by the Terminated Participant.
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(b)
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Option Not Assumed by Successor. If the Stock Option Agreement has not been assumed by the successor on or before the Change-in-Control Date, any outstanding options shall be fully vested as of the Change-in-Control Date and, in lieu of exercise, the value of such options shall be paid to the Terminated Participant in an amount equal to the excess, if any, of the aggregate fair market
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value as of the Change-in-Control Date of the shares subject to such options over the aggregate exercise price for such shares. Such payment shall be made during the 10-day period following the later of (i) the Termination Date, or (ii) the Change-in-Control Date. Notwithstanding the foregoing, if the Terminated Participant was terminated in anticipation of a Change-in-Control as described in Section 5.1 and the anticipated Change-in-Control does not occur, this Section 6.6(b) shall not apply and the terms of the Stock Option Agreement shall control.
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6.7
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Other Company Incentive Compensation Plans. The Terminated Participant shall become vested as of the Termination Date in any awards which have been granted to such Participant under any Company incentive compensation plan, program or agreements (other than those plans or agreements specified in Sections 6.2, 6.3, 6.4, 6.5 and 6.6 above) prior to the Termination Date. A Terminated Participant shall be entitled to (i) payment of any cash awards and (ii) delivery of any unrestricted shares (if such award is in the form of restricted stock), which have been granted to him or her under such plan(s) prior to the Termination Date during the 10-day period following the Termination Date.
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6.8
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Payment of Change-in-Control Benefits to Beneficiaries. In the event of the Participant’s death, all Change-in-Control Benefits that would have been paid to the Participant under this Section 6 but for his or her death shall be paid to the Participant’s Beneficiary.
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7.0
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PARTICIPATION IN NONQUALIFIED PENSION AND WELFARE BENEFIT PLANS
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7.1
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Nonqualified Deferred Compensation Plans; Restoration Retirement Plan. The Terminated Participant shall be entitled to payment of his or her benefit in any nonqualified deferred compensation or restoration pension plan of the Company (including, but not limited to, the Management Deferred Compensation Plan, the Deferred Compensation Plan for Key Management Employees and the Restoration Retirement Plan) in accordance with the terms of such plan.
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7.2
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Supplemental Senior Executive Retirement Plan. A Terminated Participant who is a member of the Senior Management Committee and would otherwise be eligible to participate in the Company’s Supplemental Senior Executive Retirement Plan but for the applicable service requirements shall (i) be deemed to have a minimum of three years of service on the Senior Management Committee and as a Senior Vice President or more senior officer and (ii) receive a grant of additional service so that such Terminated Participant has a minimum of ten years of service with the Company for benefit purposes. Such a terminated Participant shall be entitled to payment of his or her benefit under the Supplemental Senior Executive Retirement Plan in accordance with the terms of such plan upon reaching the earliest age for receipt of benefits (including any additional credited service described in the previous sentence).
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7.3
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Split-Dollar Life Insurance Policies. Following the Termination Date, the Terminated Participant shall be entitled to payment by the Company of all premiums due under any
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split-dollar life insurance arrangement of the Company (including, but not limited to, the Split Dollar Life Insurance Plan, the Executive Estate Conservation Plan and the Executive Permanent Life Insurance Plan) for any life insurance policy under which the Terminated Participant is the insured that come due during the Applicable Period following the Termination Date.
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7.4
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Employee Welfare Benefits. The Company or the applicable Subsidiary shall pay the total cost for the Terminated Participant to continue coverage after the Termination Date in the medical, dental, vision, and life insurance plans of the Company or the applicable Subsidiary in which he or she was participating on the Termination Date until the earlier of:
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(a)
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the end of the Applicable Period following the Termination Date;
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(b)
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the date, or dates, he or she receives comparable coverage and benefits under the plans, programs and/or arrangements of a subsequent employer (such coverage and benefits to be determined on a coverage-by-coverage or benefit-by-benefit basis); or
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7.5
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Applicable Period. For purposes of Section 7.3 and 7.4, the Applicable Period shall be determined as follows:
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Participant
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Applicable Period
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Tier I
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36 Months
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Tier II
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24 Months
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Tier III
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18 Months
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8.0
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TRIGGER TRUST
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8.1
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Establishment of Trigger Trust. Except as provided in the following sentence, the Board may, in its sole discretion, establish or cause to be established a Trigger Trust as described in Section 8.2 below, the purpose of which is to provide a fund for the payment of some or all of the Change-in-Control Benefits and other benefits provided under Sections 6 and 7 above to Terminated Participants following a Change-in-Control Date, and such other benefits as may be determined by the Board from time to time. Notwithstanding the preceding sentence, the Board shall not establish or cause to be established a Trigger Trust in connection with the transactions described in the Agreement and Plan of Merger by and among Duke Energy Corporation, Diamond Acquisition Corporation and the Company dated as of January 8, 2011.
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8.2
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Trigger Trust Requirements. The Trigger Trust shall be a trust:
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(a)
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of which the Company is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Code;
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(b)
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under which all Participants as of the Change-in-Control Date are beneficiaries;
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(c)
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the assets of which shall be subject to the claims of the Company’s general creditors in accordance with Internal Revenue Service Revenue Procedure 92-64; and
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(d)
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none of the assets of which shall be includable in the income of Participants solely as a result of Section 409A of the Code.
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9.0
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CLAIMS
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9.1
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Claims Procedure. If any Participant or Beneficiary, or their legal representative, has a claim for benefits which is not being paid, such claimant may file a written claim with the Committee setting forth the amount and nature of the claim, supporting facts, and the claimant’s address. Written notice of the disposition of a claim by the Committee shall be furnished to the claimant within 90 days after the claim is filed. In the event of special circumstances, the Committee may extend the period for determination for up to an additional 90 days, in which case it shall so advise the claimant. If the claim is denied, the reasons for the denial shall be specifically set forth in writing, the pertinent provisions of the Plan will be cited, including an explanation of the Plan’s claim review procedure, and, if the claim is perfectible, an explanation as to how the claimant can perfect the claim shall be provided.
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9.2
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Claims Review Procedure. If a claimant whose claim has been denied wishes further consideration of his or her claim, he or she may request the Committee to review his or her claim in a written statement of the claimant’s position filed with the Committee no later than 60 days after receipt of the written notification provided for in Section 9.1 above. The Committee shall fully and fairly review the matter and shall promptly advise the claimant, in writing, of its decision within the next 60 days. Due to special circumstances, the Committee may extend the period for determination for up to an additional 60 days.
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9.3
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Reimbursement of Expenses. If there is any dispute between the Company and a Participant with respect to a claim under the Plan, the Company shall reimburse such Participant all reasonable fees, costs and expenses incurred by such Participant with respect to such disputed claim; provided, however, that (i) such Participant is the prevailing party with respect to such disputed claim or (ii) the disputed claim is settled.
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10.0
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TAXES
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10.1
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Withholding Taxes. The Company shall be entitled to withhold from any and all payments made to a Participant under the Plan all federal, state, local and/or other taxes or imposts which the Company determines are required to be so withheld from such payments or by reason of any other payments made to or on behalf of the Participant or for his or her benefit hereunder.
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10.2
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No Guarantee of Tax Consequences. No person connected with the Plan in any capacity, including, but not limited to, the Company and any Subsidiary and their directors, officers, agents and employees makes any representation, commitment, or guarantee that any tax treatment, including, but not limited to, federal, state. and local income, estate and gift tax treatment, will be applicable with respect to amounts deferred under the Plan, or paid to or
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for the benefit of a Participant under the Plan, or that such tax treatment will apply to or be available to a Participant on account of participation in the Plan.
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11.0
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ADDITIONAL PAYMENTS
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11.1
|
Gross-Up Payment. In the event that any payment or benefit received or to be received by any Participant pursuant to the terms of the Plan other than the Gross-Up Payment described in this Section 11.1 (the “Plan Payments”) or of any other plan, arrangement or agreement of the Company or any Subsidiary (“Other Payments” and, together with the Plan Payments, the “Payments”) would be subject to the excise tax (the “Excise Tax”) imposed by Section 4999 of the Code as determined as provided below, the Company shall pay to such Participant, at the time specified in Section 11.3 below, an additional amount (the “Gross-Up Payment”) such that the net amount of such Gross-Up Payment retained by such Participant, after deduction of the Excise Tax on the Gross-Up Payment and any federal, state and local income tax on the Gross-Up Payment, and any interest, penalties or additions to tax payable by such Participant with respect to the Gross-Up Payment, shall be equal to the total present value (using the applicable federal rate (as defined in Section 1274(d) of the Code in such calculation) of the amount of the Excise Tax on the Payments at the time such Payments are to be made. Notwithstanding the foregoing provisions of this Section 11.1, if it shall be determined that a Participant in Tier II or Tier III is entitled to a Gross-Up Payment, but that the Payments would not be subject to the Excise Tax if the Payments were reduced by an amount that does not exceed ten percent (10%) of the portion of the Payments that would be treated as “parachute payments” under Section 280G of the Code, then the Plan Payments shall be reduced (but not below zero) to the maximum amount that could be paid to the Participant without giving rise to the Excise Tax (the “Safe Harbor Cap”), and no Gross-Up Payment shall be made to the Participant. The reduction of the Plan Payments hereunder, if applicable, shall be made by reducing first the Cash Payment under Section 6.1, unless an alternative method of reduction is elected by the Participant and agreed to by the Committee. For purposes of reducing the Payments to the Safe Harbor Cap, only Plan Payments (and no other Payments) shall be reduced. If the reduction of the Plan Payments would not result in a reduction of the Payments to the Safe Harbor Cap, no amounts payable under this Plan shall be reduced pursuant to this provision.
|
|
11.2
|
Determination. For purposes of determining whether any of the Payments will be subject to the Excise Tax and the amounts of such Excise Tax:
|
|
(a)
|
the total amount of the Payments shall be treated as “parachute payments” within the meaning of Section 280G(b)(2) of the Code, and all “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax, except to the extent that, in the opinion of independent
|
|
counsel selected by the Company and reasonably acceptable to such Participant (“Independent Counsel”), a Payment (in whole or in part) does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code, or such “excess parachute payments” (in whole or in part) are not subject to the Excise Tax;
|
|
(b)
|
the amount of the Payments that shall be treated as subject to the Excise Tax shall be equal to the lesser of (i) the total amount of the Payments or (ii) the amount of “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code (after applying Section 11.2(a) above); and
|
|
(c)
|
the value of any noncash benefits or any deferred payment or benefit shall be
|
|
|
determined by Independent Counsel in accordance with the principles of Sections 280G(d)(3) and (4) of the Code.
|
|
11.3
|
Date of Payment of Gross-Up Payments. The Gross-Up Payments provided for in Section 11.1 above shall be paid upon the earlier of (i) the payment to such Participant of any Payment or (ii) the imposition upon such Participant or payment by such Participant of any Excise Tax.
|
|
11.4
|
Adjustment. If it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding or the opinion of Independent Counsel that the Excise Tax is less than the amount taken into account under Section 11.1 above, such Participant shall repay to the Company within 30 days of such Participant’s receipt of notice of such final determination or opinion the portion of the Gross-Up Payment attributable to such reduction (plus the portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by such Participant if such repayment results in a reduction in Excise Tax or a federal, state and local income tax deduction) plus any interest received by such Participant on the amount of such repayment.
|
|
If it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding or the opinion of independent Counsel that the Excise Tax exceeds the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess within 30 days of the Company’s receipt of notice of such final determination or opinion.
|
|
11.5
|
Further Interpretation of Section 280G or 4999 of the Code. In the event of any change in, or further interpretation of, Section 280G or 4999 of the Code and the regulations promulgated thereunder, such Participant shall be entitled, by written notice to the Company, to request an opinion of Independent Counsel regarding the application of such change to any of the foregoing, and the Company shall use its best efforts to cause such opinion to be rendered as promptly as practicable. All fees and expenses of Independent Counsel incurred in connection with this agreement shall be borne by the Company.
|
|
12.0
|
TERM OF PLAN; AMENDMENT AND TERMINATION
|
|
12.1
|
Term of Plan, Amendment, Termination. The Plan shall be effective as of the Effective Date and shall remain in effect until the Board terminates the Plan. The Plan may be terminated, suspended or amended by the Board at any time with or without prior notice prior to a Change-in-Control; provided, however, that the Plan shall not be terminated, suspended or amended on a Change-in-Control Date or during the 3-year period following such Change-in-Control Date, and if the Plan is terminated, suspended or amended
|
|
|
thereafter, such action shall not adversely affect the benefits of any Terminated Participant.
|
|
13.0
|
COMPLIANCE WITH SECTION 409A
|
|
13.1
|
General. The Plan and the amounts payable and other benefits provided under the Plan are intended to comply with, or otherwise be exempt from, Section 409A, after giving effect to the exemptions in Treasury Regulation section 1.409A-1(b)(3) through (b)(12). The Plan shall be administered, interpreted and construed in a manner consistent with Section 409A. If any provision of the Plan is found not to comply with, or otherwise not be exempt from, the provisions of Section 409A, it shall be modified and given effect, in the sole discretion of the Committee and without requiring a Participant’s consent, in such manner as the Committee determines to be necessary or appropriate to comply with, or to effectuate an exemption from, Section 409A; provided, however, that in exercising its discretion under this Section 13.1, the Committee shall modify the Plan or any amount payable or other benefits provided under the Plan, in the least restrictive manner necessary. If the Plan or any amount payable or other benefit provided under the Plan shall be deemed not to comply with Section 409A or any related regulations or other guidance, then neither the Company, a Subsidiary, the Committee or any of their designees or agents shall be liable to any Participant or other person for actions, decisions or determinations made in good faith.
|
|
Separation from Service; Specified Employees. If a payment or benefit obligation under the Plan arises on account of a Participant’s termination of employment and such payment or benefit obligation constitutes “deferred compensation” (as defined under Treasury Regulation section 1.409A-1(b)(1), after giving effect to the exemptions in Treasury Regulation section 1.409A-1(b)(3) through (b)(12), it shall be payable only after the Participant’s Separation from Service; provided, however, that if the Participant is a Specified Employee, any payment that is scheduled to be paid within six months after such Separation from Service shall accrue without interest and shall be paid on the date that is six months after such Separation from Service or, in the case of a payment or benefit payable in installments, on the first day of the seventh month beginning after the date of the Participant’s Separation from Service or, if earlier, within fifteen days after the Participant’s death (and the payment on the first day of the seventh month beginning after the date of the Participant’s Separation from Service shall include any installments that would have been paid during such period after the Separation from Service if the Participant was not a Specified Employee).
|
|
Reimbursement Benefits. With respect to any reimbursement of expenses of, or any provision of in-kind benefits to, a Participant as provided in the Plan, such reimbursement of expenses or provision of in-kind benefits shall be subject to the following limitations: (i) the expenses eligible for reimbursement or the amount of in-kind benefits provided in one taxable year shall not affect the expenses eligible for reimbursement or the amount of in-kind benefits provided in any other taxable year, except for any medical reimbursement arrangement providing for the reimbursement of expenses referred to in Section 105(b) of the Code; (ii) the reimbursement of an eligible expense shall be made as specified in the Plan and in no event later than the end of the year in which such expense was incurred and (iii) the right to reimbursement or in-kind benefit shall not be subject to liquidation or exchange for another benefit.
|
|
13.2
|
Specific Terms Applicable to Change-in-Control Benefits Subject to Section 409A. Without limiting the effect of Section 13.1 above, and notwithstanding any other provision in the Plan to the contrary, the following provisions shall, to the extent required under
|
|
|
Section 409A, related regulations or other guidance, apply with respect to Change-in-Control Benefits deemed to involve the deferral of compensation under Section 409A:
|
|
(a)
|
Distributions: Distributions may be made with respect to Change-in-Control Benefits subject to Section 409A not earlier than upon the occurrence of one or more of the following events: (A) Separation from Service; (B) disability; (C) death; (D) a specified time or pursuant to a fixed schedule; (E) a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company, as defined in Section 2.5.2; or (F) the occurrence of an unforeseeable emergency. Each of the preceding distribution events shall be defined and interpreted in accordance with Section 409A and related regulations or other guidance.
|
|
(b)
|
Specified Employees: With respect to Participants who are Specified Employees, a distribution of deferred compensation due to Separation from Service may not be made before the date that is six months after the Termination Date (or, if earlier, the date of death of the Participant), except as may be otherwise permitted pursuant to Section 409A. To the extent that a Participant is subject to this section and a distribution is to be paid in installments, through an annuity, or in some other manner where payment will be periodic, the Participant shall be paid, during the seventh month following the Termination Date, the aggregate amount of payments he or she would have received but for the application of this section; all remaining payments shall be made in their ordinary course.
|
|
(c)
|
No Acceleration: Unless permissible under Section 409A, related regulations or other guidance, the acceleration of the time or schedule for the payment of any Change-in-Control Benefit under the Plan is prohibited.
|
|
14.0
|
MISCELLANEOUS
|
|
14.1
|
Offset. The Change-in-Control Benefits shall be reduced by any payment or benefit made or provided by the Company or any Subsidiary to the Participant pursuant to (i) any severance plan, program, policy or arrangement of the Company or any subsidiary of the Company not otherwise referred to in the Plan, (ii) any employment agreement between the Company or any Subsidiary and the Participant, and (iii) any federal, state or local statute, rule, regulation or ordinance.
|
|
14.2
|
No Right, Title, or Interest in Company Assets. Participants shall have no right, title, or interest whatsoever in or to any assets of the Company or any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, Beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. Subject to Section 8 above, all payments to be made hereunder shall be paid from the general funds of the Company and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts except as expressly set forth in the Plan.
|
|
14.3
|
No Right to Continued Employment. The Participant’s rights, if any, to continue to serve the Company or any Subsidiary as an employee shall not be enlarged or otherwise affected
|
|
|
by his or her designation as a Participant under the Plan, and the Company or the applicable Subsidiary reserves the right to terminate the employment of any employee at any time. The adoption of the Plan shall not be deemed to give any employee, or any other individual any right to be selected as a Participant or to continued employment with the Company or any Subsidiary.
|
|
14.4
|
Other Rights. The Plan shall not affect or impair the rights or obligations of the Company, any Subsidiary or a Participant under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan.
|
|
14.5
|
Governing Law. The Plan shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.
|
|
14.6
|
Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent.
|
|
14.7
|
Incapacity. If the Committee determines that a Participant or a Beneficiary is unable to care for his or her affairs because of illness or accident or because he or she is a minor, any benefit due the Participant or Beneficiary may be paid to the Participant’s spouse or to any other person deemed by the Committee to have incurred expense for such Participant (including a duly appointed guardian, committee or other legal representative), and any such payment shall be a complete discharge of the Company’s obligation hereunder.
|
|
14.8
|
Transferability of Rights. The Company shall have the unrestricted right to transfer its obligations under the Plan with respect to one or more Participants to any person, including, but not limited to, any purchaser of all or any part of the Company’s business. No Participant or Beneficiary shall have any right to commute, encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Participant or Beneficiary may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be non-assignable and nontransferable, except to the extent required by law. Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Participant or the spouse of a Participant shall, in the sole discretion of the Committee (after consideration of such facts as it deems pertinent), be grounds for terminating any rights of the Participant or Beneficiary to any portion of the Plan benefits not previously paid.
|
|
IN WITNESS WHEREOF, this instrument has been executed this 31st day of October, 2011.
|
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
Page
|
|||||
PREAMBLE
|
1
|
||||
ARTICLE I DEFINITIONS
|
2
|
||||
1.1
|
Account Balance
|
2
|
|||
1.2
|
Additional Deferral Election
|
2
|
|||
1.3
|
Affiliated Company
|
2
|
|||
1.4
|
Board
|
2
|
|||
1.5
|
Board Committee
|
2
|
|||
1.6
|
Change in Control
|
2
|
|||
1.7
|
Change of Form Election
|
3
|
|||
1.8
|
Change-of-Investment Election
|
4
|
|||
1.9
|
Code
|
4
|
|||
1.10
|
Committee
|
4
|
|||
1.11
|
Company
|
4
|
|||
1.12
|
Company Incentive Plans
|
4
|
|||
1.13
|
Continuing Directors
|
4
|
|||
1.14
|
Deemed Investment Return
|
4
|
|||
1.15
|
Deferral Election
|
4
|
|||
1.16
|
Deferrals
|
5
|
|||
1.17
|
Effective Date
|
5
|
|||
1.18
|
Eligible Employee
|
5
|
|||
1.19
|
Employee Stock Incentive Plan
|
5
|
|||
1.20
|
Enrollment Form
|
5
|
|||
1.21
|
ERISA
|
5
|
|||
1.22
|
[Reserved]
|
5
|
|||
1.23
|
Investment Election
|
5
|
|||
1.24
|
Matching Allocation
|
5
|
|||
1.25
|
Net Salary
|
6
|
|||
1.26
|
Participant
|
6
|
|||
1.27
|
Participant Accounts
|
6
|
|||
1.28
|
Participant Company Account
|
6
|
|||
1.29
|
Participant Deferral Account
|
6
|
|||
1.30
|
Participant Matchable Deferral
|
6
|
|||
1.31
|
Payment Commencement
|
6
|
|||
1.32
|
Phantom Investment Fund
|
7
|
|||
1.33
|
Phantom Funds Account
|
7
|
|||
1.34
|
Phantom Investment Subaccount
|
7
|
|||
1.35
|
Phantom Stock Unit
|
7
|
|||
1.36
|
Plan
|
7
|
|||
1.37
|
Plan Year
|
7
|
|||
1.38
|
Plan Year Accounts
|
7
|
|||
1.39
|
Progress Energy 401(k) Savings & Stock Ownership Plan
|
8
|
|||
1.40
|
Retirement Date
|
8
|
|||
1.41
|
Salary
|
8
|
1.42
|
Section 409A
|
8
|
|||
1.43
|
Separation from Service
|
8
|
|||
1.44
|
SMC Participant
|
8
|
|||
1.45
|
Sponsor
|
8
|
|||
1.46
|
SSERP
|
8
|
|||
1.47
|
Valuation Date
|
9
|
|||
1.48
|
Value
|
9
|
|||
1.49
|
Years of Service
|
9
|
|||
ARTICLE II PARTICIPATION
|
9
|
||||
2.1
|
Eligibility
|
9
|
|||
2.2
|
Commencement of Participation
|
9
|
|||
2.3
|
Annual Participation Agreement
|
9
|
|||
2.4
|
Election of Phantom Investment Subaccounts
|
10
|
|||
ARTICLE III DEFERRAL ELECTIONS
|
10
|
||||
3.1
|
Participant Deferred Salary Elections
|
10
|
|||
3.2
|
Matching Allocations
|
11
|
|||
ARTICLE IV ACCOUNTS
|
11
|
||||
4.1
|
Maintenance of Accounts
|
11
|
|||
4.2
|
Separate Plan Year Accounts
|
11
|
|||
4.3
|
Phantom Investment Subaccounts
|
12
|
|||
4.4
|
Administration of Deferral Accounts
|
12
|
|||
4.5
|
Administration of Company Accounts
|
12
|
|||
4.6
|
Change of Phantom Investment Subaccounts and Phantom Stock Units
|
13
|
|||
4.7
|
Transferred Accounts
|
13
|
|||
ARTICLE V VESTING
|
14
|
||||
5.1
|
Vesting
|
14
|
|||
ARTICLE VI DISTRIBUTIONS
|
14
|
||||
6.1
|
Distribution Elections
|
14
|
|||
6.2
|
Change-of-Form Elections and Additional Deferral Elections
|
15
|
|||
6.3
|
Payment
|
15
|
|||
6.4
|
Unforeseeable Emergency
|
15
|
|||
6.5
|
Separation from Service
|
16
|
|||
6.6
|
Taxes
|
17
|
|||
6.7
|
Acceleration of Payment
|
17
|
|||
ARTICLE VII DEATH BENEFITS
|
17
|
||||
7.1
|
Designation of Beneficiaries
|
17
|
|||
7.2
|
Death Benefits
|
17
|
|||
ARTICLE VIII CLAIMS
|
18
|
||||
8.1
|
Claim Procedure
|
18
|
8.2
|
Claims Review Procedure
|
18
|
|||
ARTICLE IX ADMINISTRATION
|
18
|
||||
9.1
|
Committee
|
18
|
|||
9.2
|
Authority
|
18
|
|||
ARTICLE X AMENDMENT AND TERMINATION OF THE PLAN
|
19
|
||||
10.1
|
Amendment of the Plan
|
19
|
|||
10.2
|
Termination of the Plan
|
19
|
|||
10.3
|
No Impairment of Benefits
|
20
|
|||
ARTICLE XI FUNDING AND CLAIM STATUS
|
20
|
||||
11.1
|
General Provisions
|
20
|
|||
ARTICLE XII EFFECT ON EMPLOYMENT OR ENGAGMEENT
|
21
|
||||
12.1
|
General
|
21
|
|||
ARTICLE XIII GOVERNING LAW
|
21
|
||||
13.1
|
General
|
21
|
|||
EXHIBIT A
|
1.1
|
Account Balance
|
1.2
|
Additional Deferral Election
|
1.3
|
Affiliated Company
|
1.4
|
Board
|
1.5
|
Board Committee
|
1.6
|
Change in Control
|
(a)
|
the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the “beneficial owner” (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor’s then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or
|
(b)
|
the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor’s then outstanding voting securities; or
|
(c)
|
the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or
|
(d)
|
the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or
|
(e)
|
the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets; or
|
(f)
|
the date of any event which the Board determines should constitute a Change in Control.
|
1.7
|
Change of Form Election
|
1.8
|
Change-of-Investment Election
|
1.9
|
Code
|
1.10
|
Committee
|
1.11
|
Company
|
1.12
|
Company Incentive Plans
|
1.13
|
Continuing Directors
|
1.14
|
Deemed Investment Return
|
1.15
|
Deferral Election
|
1.16
|
Deferrals
|
1.17
|
Effective Date
|
1.18
|
Eligible Employee
|
1.19
|
Employee Stock Incentive Plan
|
1.20
|
Enrollment Form
|
1.21
|
ERISA
|
1.22
|
[Reserved]
|
1.23
|
Investment Election
|
1.24
|
Matching Allocation
|
1.25
|
Net Salary
|
1.26
|
Participant
|
1.27
|
Participant Accounts
|
1.28
|
Participant Company Account
|
1.29
|
Participant Deferral Account
|
1.30
|
Participant Matchable Deferral
|
1.31
|
Payment Commencement
|
1.32
|
Phantom Investment Fund
|
1.33
|
Phantom Funds Account
|
1.34
|
Phantom Investment Subaccount
|
1.35
|
Phantom Stock Unit
|
1.36
|
Plan
|
1.37
|
Plan Year
|
1.38
|
Plan Year Accounts
|
1.39
|
Progress Energy 401(k) Savings & Stock Ownership Plan
|
1.40
|
Retirement Date
|
1.41
|
Salary
|
1.42
|
Section 409A
|
1.43
|
Separation from Service
|
1.44
|
SMC Participant
|
1.45
|
Sponsor
|
1.46
|
SSERP
|
1.47
|
Valuation Date
|
1.48
|
Value
|
1.49
|
Years of Service
|
2.1
|
Eligibility
|
2.2
|
Commencement of Participation
|
2.3
|
Annual Participation Agreement
|
2.4
|
Election of Phantom Investment Subaccounts
|
3.1
|
Participant Deferred Salary Elections
|
3.2
|
Matching Allocations
|
4.1
|
Maintenance of Accounts
|
4.2
|
Separate Plan Year Accounts
|
4.3
|
Phantom Investment Subaccounts
|
4.4
|
Administration of Deferral Accounts
|
4.5
|
Administration of Company Accounts
|
4.6
|
Change of Phantom Investment Subaccounts and Phantom Stock Units
|
4.7
|
Transferred Accounts
|
5.1
|
Vesting
|
6.1
|
Distribution Elections
|
6.2
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Change-of-Form Elections and Additional Deferral Elections
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6.3
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Payment
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6.4
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Unforeseeable Emergency
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6.5
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Separation from Service
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6.6
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Taxes
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6.7
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Acceleration of Payment
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7.1
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Designation of Beneficiaries
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7.2
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Death Benefit
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8.1
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Claims Procedure
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8.2
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Claims Review Procedure
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9.1
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Committee
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9.2
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Authority
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10.1
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Amendment of the Plan
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10.2
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Termination of the Plan
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10.3
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No Impairment of Benefits
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11.1
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General Provisions
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12.1
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General
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13.1
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General
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By:
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PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
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1.1
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Whereas, Progress Energy, Inc. (the “Company”) adopted this Non-Employee Director Deferred Compensation Plan (the “Plan”) as of December 16, 1981 (the “Effective Date”).
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1.2
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Whereas, the Company has maintained and operated the Plan since the Effective Date pursuant to individual deferral agreements with the Company’s Directors.
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1.3
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Whereas, the Company adopted this written restatement of the Plan effective as of January 1, 2008, in order to update and clarify the rights and obligations under the Plan of the Company and its Directors and to change the amount of the automatic deferral from $15,000 to $30,000 per year.
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2.1
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Purpose. The purpose of the Plan is to permit the Company’s non-employee Directors to defer all or a portion of their annual retainers and meeting fees in the form of Stock Units (as defined below), thereby aligning the interests of the Directors with the interests of the Company’s shareholders.
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2.2
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Limitations. Distributions required or contemplated by this Plan or actions required to be taken under this Plan shall not be construed as creating a trust of any kind or a fiduciary relationship between the Company and any Director, any Director’s designated beneficiary, or any other person.
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2.3
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Code Section 409A. This Plan is intended to comply with the requirements of Section 409A of the Internal Revenue Code and the regulations and other guidance issued thereunder, as in effect from time to time (“Section 409A”). To the extent a provision of the Plan is contrary to or fails to address the requirements of Section 409A, the Plan shall be construed and administered as necessary to comply with such requirements until this Plan is appropriately amended.
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The following terms shall have the following meanings unless the context inwhich they are used clearly indicates that some other meaning is intended:
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3.1
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“Account” means the bookkeeping account maintained for each Director which shall be credited with all Voluntary Deferrals elected by a Director, all Automatic Deferrals and Matching Contributions made on behalf of a Director, and all dividend credits with respect to Stock Units in the Account, and other adjustments thereto.
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3.2
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“Automatic Deferral” means the portion of a Director’s annual retainer that is automatically deferred under this Plan pursuant to Section 6.1.
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3.3
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“Beneficiary” means the beneficiary or beneficiaries designated by a Director pursuant to Section 10.7 to receive the benefits, if any, payable on behalf of the Director under the Plan after the death of such Director, or, when there has been no such designation or an invalid designation, the individual or entity, or the individuals or entities, who will receive such amount.
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3.4
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“Board” means the Board of Directors of the Company.
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3.5
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“Change in Control” means “Change in Control,” as defined in Section 2.5.1 of the Progress Energy, Inc. Management Change in Control Plan (Amended and Restated Effective January 1, 2007).
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3.6
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“Code” means the Internal Revenue Code of 1986, as amended.
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3.7
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“Committee” means the Board’s Committee on Corporate Governance.
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3.8
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“Common Stock” means the common stock of the Company.
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3.9
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“Company” means Progress Energy, Inc., a North Carolina corporation, including any successor entity.
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3.10
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“Compensation” means a Director’s annual retainer fees, meeting fees and committee fees otherwise payable to such Director during his or her current term as a Director.
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3.11
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“Continuing Directors” means the members of the Board as of January 1, 2007; provided, however, that any person becoming a Director subsequent to such date whose election or nomination for election was supported by 75 percent or more of the Directors who then comprised the Continuing Directors shall be considered to be a Continuing Director.
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3.12
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“Deferral Election” means an annual irrevocable election, made in accordance with Section 6 in such form (electronic or otherwise) as approved and provided by the Committee, to defer the receipt of a designated amount of Compensation.
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3.13
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“Deferrals” mean Automatic Deferrals and Voluntary Deferrals.
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3.14
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“Director” means any person (other than a person who is an employee of the Company) who has been elected to serve as a member of the Board and any former member of the Board for whom an Account is maintained under this Plan.
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3.15
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“Effective Date” means January 1, 2008.
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3.16
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“Fair Market Value” means the closing price of Common Stock on the date a Director’s Account is credited (or on the last preceding trading date if Common Stock is not traded on such date) if Common Stock is readily tradable on a national securities exchange or other market system. If the Common Stock is not readily tradable on a national securities exchange or other market system, an amount determined in good faith by the Board as the fair market value of Common Stock on the date of determination.
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3.17
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“Plan” means this Progress Energy, Inc. Non-Employee Director Deferred Compensation Plan, as amended from time to time.
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3.18
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“Plan Year” means the calendar year ending on each December 31.
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3.19
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“Stock Units” means investment units, each of which is deemed to be equivalent to one share of Common Stock.
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3.20
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“Voluntary Deferrals” means the Compensation that a Director elects to defer under this Plan pursuant to Section 6.2.
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4.1
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Responsibility. The Committee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms.
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4.2
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Authority of the Committee. The Committee shall have all the discretionary authority that may be necessary or helpful to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following:
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(a)
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to correct any defect, supply any omission, and reconcile any inconsistency in the Plan in such manner and to such extent as it shall deem appropriate in its sole discretion to carry the same into effect;
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(b)
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to issue administrative guidelines as an aid to administer the Plan and make changes in such guidelines as it from time to time deems proper;
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(c)
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to make rules for carrying out and administering the Plan and make changes in such rules as it from time to time deems proper;
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(d)
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to the extent permitted under the Plan, grant waivers of Plan terms, conditions, restrictions and limitations; and
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(e)
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to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan.
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4.3
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Action by the Committee. The Committee may act only by a majority of its members. Subject to applicable law, any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee.
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4.4
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Delegation of Authority. Subject to applicable law, the Committee may delegate to one or more of its members, or to one or more agents, such duties, responsibility and authority with respect to this Plan as it may deem advisable. In addition, the Committee, or any person to whom it has delegated duties, responsibility and authority as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid by the Company or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee.
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4.5
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Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive on all Directors and their heirs, successors and legal representatives.
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5.1
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Eligibility and Participation. All Directors are automatically eligible and shall participate in the Plan.
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6.1
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Automatic Deferrals. A portion of each Director’s annual retainer, in an amount established from time to time by the Board, shall automatically be deferred under this Plan, which amount for purposes of the Plan shall be referred to as an “Automatic Deferral.” Unless and until changed by the Board, the annual amount of the Automatic Deferral shall be $30,000.
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6.2
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Voluntary Deferrals. In addition to Automatic Deferrals, a Director may elect to defer all or any portion, expressed as a whole percentage, of his or her remaining Compensation by filing the appropriate Deferral Election with the Committee's designee. Deferrals under this Section 6.2 shall be known as “Voluntary Deferrals.”
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6.3 First Term Deferral Elections. An individual who is elected to serve as a Director or who is nominated for election as a Director (other than an individual who was a Director immediately before such election or nomination) shall have the right at any time before the end of the thirty (30) day period immediately following the effective date of his or her election as a Director to elect to defer the payment of all or any portion of his or her future Compensation by filing the appropriate Deferral Election with the Committee's designee.
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6.4
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Annual Deferral Elections. Before the beginning of each calendar year, a Director shall have the right to elect to defer the payment of his or her Compensation which is attributable to services rendered as a Director during such calendar year by filing the appropriate Deferral Election with the Committee's designee. Any Deferral Election which is made and which is not revoked before the beginning of such calendar year shall become irrevocable on the first day of such calendar year and shall remain irrevocable through the end of such calendar year.
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6.5
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Automatic Renewal of Deferral Elections. If a Director makes a Deferral Election under either Section 6.3 or Section 6.4 for any calendar year and does not revoke such Deferral Election before the beginning of any subsequent calendar year, such Deferral Election shall remain in effect for each such subsequent calendar year and shall be irrevocable through the end of each subsequent calendar year.
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6.6
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Account Credits. The Compensation which a Director defers under this Section shall be credited to his or to her Account effective as of the business day on which such Compensation would otherwise have been paid to the Director.
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7.1
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Conversion of Deferrals to Stock Units. All Deferrals shall be converted to Stock Units on the day such Deferrals are credited to a Director’s Account. The number of Stock Units to be credited shall be determined by dividing the dollar value of the Deferrals credited to a Director’s Account by the Fair Market Value of one share of Common Stock as of the date on which the Deferrals are converted to Stock Units.
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7.2
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Conversion of Dividend Equivalents to Stock Units. Directors’ Accounts will be credited with additional fully vested Stock Units as of the payment date of any dividends declared on the Common Stock. The number of additional Stock Units credited to an Account shall be determined by dividing (i) the product of the per-share cash dividend amount (or the value of any non-cash dividend) times the number of Stock Units credited to the Account as of the record date for such dividend, by (ii) the Fair Market Value of one share of Common Stock as of the dividend payment date.
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7.3
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No Other Investment Alternatives. Nothing contained in this Plan shall be construed to give any Director any power or control to make investment decisions with respect to Deferrals other than the conversion to Stock Units as provided in this Section 7. Nothing contained in the Plan shall be construed to require the Company or the Committee to fund any Director's Account.
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8.1
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Vesting. A Director shall be fully vested at all times in the Stock Units credited to his or her Account.
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8.2
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Timing and Form of Distributions
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(a)
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Election Regarding Distributions. Directors must make or have in effect an election for each Plan Year regarding the timing of distributions to be made under the Plan as set forth in Section 8.2(b) below (a “Distribution Election”). The Distribution Election shall have been or shall be made pursuant to a “Method of Payment Agreement” or otherwise pursuant to a Director’s Deferral Election.
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(b)
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Timing of Distributions. A director’s Distribution Election shall specify whether the Director shall receive distributions (i) in a single lump sum payment in cash during the 60-day period following the first business day of the calendar year following the year in which the Director’s service as a member of the Board terminates for any reason or (ii) in a series of annual installments (not to exceed 10) commencing during the 60-day period following the first business day of the calendar year following the year in which the Director’s service as a member of the Board terminates for any reason. If the Director has elected to receive installment payments, the amount of each installment shall be determined by dividing the number of Stock Units credited to the Director’s Account on the first business day preceding the date of payment by the number of installments remaining to be paid, and then converting the number of Stock Units determined thereby into a cash payment as provided in Section 8.2(c) below.
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(c)
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Form of Distributions. All distributions under this Plan shall be in cash. Prior to any distribution, Stock Units shall be converted into the right to receive a cash payment equal to the number of Stock Units being distributed multiplied by the Fair Market Value of a share of Common Stock on the date of distribution.
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(d)
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Death. Notwithstanding anything in this Plan to the contrary (and regardless of any distribution election in the Director’s Deferral Agreement, Method of Payment Agreement or Deferral Election), the value of the Director's entire Account shall be distributed in a single lump sum to the Director’s Beneficiary commencing with the 60-day period after the Director’s death.
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8.3
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Unforeseeable Emergency Payments. In the event a Director incurs a financial hardship as a result of an “unforeseeable emergency” (as such term is defined below), the Director may apply to the Committee for the distribution of all or a portion of the Director’s Account. The application shall provide such information and be in such form as the Committee shall require. The Committee, in the exercise of its sole and absolute discretion, may approve or deny the request in whole or in part. The term “unforeseeable emergency” shall mean a severe financial hardship to the Director resulting from an illness or accident of the Director, the Director’s spouse, or a dependent (as defined in Section 152(a) of the Code) of the Director, loss of the Director’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Director. In no event may the amounts distributed with respect to an unforeseeable emergency exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement, cancellation of Deferrals for the remainder of the Plan Year, or compensation by insurance or otherwise or by liquidation of the Director’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship). If a Director receives a distribution of all or a portion of the Director’s Account pursuant to this Section 8.3, any Deferral Election in effect for the Director shall be cancelled, and the Director shall make no additional Voluntary Deferrals for the remainder of the current Plan Year. The Director may make Voluntary Deferrals with respect to future Plan Years by delivering a new Deferral Election in accordance with Section 6.4. Notwithstanding any provision in the Plan to the contrary, any payment made pursuant to this Section 9.3 shall comply with Section 409A(a)(2)(A)(vi) of the Code and the regulations (or similar guidance) promulgated thereunder (or under any successor provisions).
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9.1
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Term. The Plan shall be effective as of the Effective Date. The Plan shall remain in effect until the Board terminates the Plan.
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9.2
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Termination or Amendment of Plan. The Board may amend, suspend or terminate the Plan at any time with or without prior notice; provided,
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however, that no action authorized by this Section 10.2 shall reduce the balance or adversely affect the Account of a Director.
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10.1
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Adjustments. If there shall be any change in Common Stock through merger, consolidation, reorganization, recapitalization, stock dividend, stock split, reverse stock split, split up, spin-off, combination of shares, exchange of shares, dividend in kind or other like change in capital structure or distribution (other than normal cash dividends) to holders of Common Stock, the number of Stock Units and the Director’s Account shall be adjusted to equitably reflect such change or distribution.
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10.2
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Governing Law. The Plan and all actions taken in connection herewith shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.
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10.3
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No Right, Title or Interest in Company Assets. Directors shall have no right, title, or interest whatsoever in or to any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Director, beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. All payments to be made hereunder shall be paid from the general funds of the Company and, except as provided in Section 10.10 below, no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts.
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10.4
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No Right to Continued Service. The Director’s rights, if any, to continue to serve the Company as a member of the Board shall not be enlarged or otherwise affected by his or her participation in the Plan.
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10.5
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Other Rights. The Plan shall not affect or impair the rights or obligations of the Company or a Director under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan.
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10.6
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Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent. If, however, the Committee determines in its sole discretion that any term or condition of the Plan which is invalid or unenforceable is
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material to the interests of the Company, the Committee may declare the Plan null and void in its entirety.
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10.7
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Beneficiary Designation. Every Director may file with the Company a designation in such form (electronic or otherwise) as approved and provided by the Company of one or more persons as the Beneficiary who shall be entitled to receive the benefits, if any, payable under the Plan after the Director’s death. A Director may from time to time revoke or change such Beneficiary designation without the consent of any prior Beneficiary by filing a new designation with the Company. The last such designation received by the Company shall be controlling; provided, however, that no designation, or change or revocation thereof, shall be effective unless received by the Company prior to the Director’s death, and in no event shall it be effective as of any date prior to such receipt. All decisions of the Committee concerning the effectiveness of any Beneficiary designation and the identity of any Beneficiary shall be final. If a Beneficiary shall die after the death of the Director and prior to receiving the payment(s) that would have been made to such Beneficiary had such Beneficiary’s death not occurred, then for the purposes of the Plan the payment(s) that would have been received by such Beneficiary shall be made to the Beneficiary’s estate.
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10.8
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Transferability of Rights. No Director or spouse of a Director shall have any right to encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Director or such spouse may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be nonassignable and nontransferable, except to the extent required by law. Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Director or the spouse of a Director shall be null and void and without effect.
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10.9
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Entire Document. The Plan, as set forth herein, supersedes any and all prior practices, understandings, agreements, descriptions or other non-written arrangements with respect to the subject matter hereof.
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10.10
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Change in Control. In the case of a Change in Control, the Company, subject to the restrictions in this Section 11.10 and in Section 11.3, shall irrevocably set aside funds in one or more grantor trusts in an amount that is sufficient to pay each Director the value of the Director’s Account as of the date on which the Change in Control occurs; provided, however, that the Company shall establish no such trust if the assets thereof are includable in the income of Directors thereby pursuant to Section 409A(b). Notwithstanding the preceding sentence, the Company shall not set aside funds, revocably or irrevocably, in one or more grantor trusts in connection with the transactions described in the Agreement and Plan of Merger between the Company and Duke Energy Corporation dated as of January 8, 2011.
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By:
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PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
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1.1
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Whereas, Carolina Power & Light Company ("CP&L") adopted the Carolina Power & Light Company Retirement Plan for Outside Directors (the "Directors Retirement Plan") in 1986, which provided for a fixed-dollar retirement benefit for non-employee directors of CP&L following their termination of service as a member of the Board of Directors of CP&L.
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1.2
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Whereas, effective January 1, 1998, CP&L froze the Directors Retirement Plan so that no further benefits would accrue under such plan, and adopted the Carolina Power & Light Company Non-Employee Director Stock Unit Plan (the "Plan"), the purpose of which was to provide deferred compensation to the non-employee directors of CP&L based on the value of CP&L common stock.
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1.3
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Whereas, sponsorship of the Plan was transferred to CP&L Energy, Inc. effective August 1, 2000, and the name of the Plan was subsequently changed to Progress Energy, Inc. Non-Employee Director Stock Unit Plan.
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1.4
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Whereas, the Company amended and restated the Plan effective January 1, 2005 to increase the Annual Stock Unit Grant and to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the "Code"), regarding the payment of benefits from the Plan.
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1.5
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Whereas, the Company amended and restated the Plan effective January 1, 2006, for the purposes of (i) changing the date of the allocation of the annual stock unit grant to participants' accounts from the date of the Company’s annual meeting of shareholders to the first business day in January of each year; and (ii) to eliminate the requirement that to be eligible to receive an annual stock unit grant a participant must have served on the Board for one year.
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1.6
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Whereas, the Company adopts this amended and restated Plan effective January 1, 2008, for the purpose of making certain administrative changes, to amend the determination of Common Stock Value in the Plan, and to change the annual stock unit grant provided by the Plan from a fixed 1,200 unit grant to a targeted value of $60,000.
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2.1
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Purpose. The purpose of the Plan is to attract and retain highly qualified individuals as non-employee directors of the Company, and to provide deferred compensation to the Company's non-employee directors based on the value of the Company's stock.
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3.1
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"Annual Stock Unit Grant" shall mean a grant of Stock Units equivalent to $60,000 as described in Section 5.2 below.
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(1)
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the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Company, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Company representing twenty-five percent (25%) or more of the combined voting power of the Company's then outstanding securities (excluding the acquisition of securities of the Company by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Company); or
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(2)
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the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Company's then outstanding voting securities; or
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(3)
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the date of consummation of a merger, share exchange or consolidation of the Company with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Company or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or
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(4)
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the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Company (other than such an offer by the Company for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board of Directors; or
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(5)
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the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets; or
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(6)
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the date of any event which the Board of Directors determines should constitute a Change in Control.
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3.6
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"Company" shall mean Progress Energy, Inc., a North Carolina corporation, including any successor entity.
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3.7
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"Continuing Directors" shall mean the members of the Board as of January 1, 2007; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by 75 percent (75%) or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director.
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3.8
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"Distribution Date" shall mean the later of (i) the date a Participant is no longer a member of the Board and otherwise “separates from service” with the Company, as defined for purposes of Section 409A of the Code, or (ii) the date such Participant attains age 65.
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3.9
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"Effective Date" shall mean January 1, 1998. The Plan has been subsequently amended and restated effective July 10, 2002, January 1, 2005, January 1, 2006, January 1, 2007, and January 1, 2008.
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3.10
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"Common Stock Value" shall mean:
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(1)
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the closing price of Common Stock on the relevant date (or on the last preceding trading date if Common Stock was not traded on the relevant date) if Common Stock is readily tradable on a national securities exchange or other market system; or
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(2)
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an amount determined in good faith by the Board as the fair market value of Common Stock on the date of determination if Common Stock is not readily tradable on a national securities exchange or other market system.
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3.11
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"Initial Stock Unit Grant" shall mean a grant of Stock Units as described in Section 5.1 below.
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3.12
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"Participant" shall mean a member of the Board who is not an employee of the Company or any of its Subsidiaries.
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3.13
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"Stock Unit" shall mean a unit maintained by the Company for bookkeeping purposes, equal in value to one (1) share of Common Stock.
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3.14
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"Stock Unit Account” shall mean a bookkeeping account established and maintained (or caused to be established and maintained) by the Company for the Participant which shall record the number of Stock Units granted to the Participant under Section 5 below. This account shall be established (or caused to be established) by the Company for bookkeeping purposes only, and no separate funds shall be segregated by the Company for the benefit of the Participant.
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3.15
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"Plan" shall mean the Progress Energy, Inc. Non-Employee Director Stock Unit Plan.
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3.16
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"Subsidiary" shall mean a corporation of which the Company directly or indirectly owns more than 50 percent of the Voting Stock (meaning the capital stock of any class or classes having general voting power under ordinary circumstances, in the absence of contingencies, to elect the directors of a corporation) or any other business entity in which the Company directly or indirectly has an ownership interest of more than fifty percent (50%).
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4.1
|
Responsibility. The Committee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms.
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4.2
|
Authority of the Committee. The Committee shall have all the discretionary authority that may be necessary or helpful to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following:
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|
(g)
|
to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan.
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4.3
|
Action by the Committee. The Committee may act only by a majority of its members. Any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee.
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4.4
|
Delegation of Authority. The Committee may delegate to one or more of its members, or to one or more agents, such administrative duties as it may deem advisable; provided, however, that any such delegation shall be in writing. In addition, the Committee, or any person to whom it has delegated duties as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid by the Company, or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee.
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4.5
|
Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive on all Participants and their heirs, successors, and legal representatives.
|
4.6
|
Information. The Company shall furnish to the Committee in writing all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. Such information may include, but shall not be limited to, the full names of all Participants, their earnings and their dates of birth, employment, retirement or death. Such information shall be conclusive for all purposes of the Plan, and the Committee shall be entitled to rely thereon without any investigation thereof.
|
4.7
|
Self-Interest. No member of the Committee may act, vote or otherwise influence a decision of the Committee specifically relating to his or her benefits, if any, under the Plan.
|
5.1
|
Rollover. CP&L granted an Initial Stock Unit Grant to the Participants listed on Schedule A (who were participants in the CP&L Retirement Plan for Outside Directors) who were elected by December 31, 1997, pursuant to an election made in writing to the CP&L Vice President-Human Resources to rollover their accrued benefit under such plan (the
|
|
"Accrued Benefit") into the Plan. The number of shares underlying each Initial Stock Unit Grant was equal to the present value of the Participant's Accrued Benefit as of December 31, 1997, divided by the Common Stock Value of CP&L common stock on the last trading day of 1997. Any fractional Stock Unit greater than 50 percent was rounded up to one Stock Unit, and any fractional Stock Unit equal to or less than 50 percent was disregarded. Such number of Stock Units underlying the Initial Stock Unit Grant was entered and recorded in the Participant's Stock Unit Account, and later adjusted to reflect the change in the capital structure of CP&L as a result of which CP&L became a Subsidiary of the Company.
|
5.2
|
Annual Grant. Effective January 1, 2008, the Company shall grant to each Participant an Annual Stock Unit Grant equal to the number of Stock Units equivalent to $60,000 (rounded up to the next whole unit). The Annual Stock Unit Grant shall be made the first business day of January. The Company shall enter and record (or shall cause to be entered and recorded) in the Participant's Stock Unit Account such number of Stock Units underlying the Annual Stock Unit Grant.
|
5.3
|
Dividend Stock Units. On the date that any holder of Common Stock receives a dividend with respect to Common Stock, the Company shall grant to each Participant, and shall enter and record (or shall cause to be entered and recorded) in each such Participant's Stock Unit Account a number of Stock Units equal to the result of (x) the dollar amount of such dividend paid with respect to one share of Common Stock multiplied by (y) the number of Stock Units in the Stock Unit Account as of the date such dividend is paid divided by (z) the Common Stock Value as of the date such dividend is paid. Any fractional Stock Unit greater than fifty percent (50%) shall be rounded up to one Stock Unit, and any fractional Stock Unit equal to or less than fifty percent (50%) shall be disregarded.
|
6.1
|
Vesting. A Director shall be fully vested at all times in the Stock Units credited to his or her Account.
|
6.2
|
Timing of Benefit. In accordance with Section 6.4 below, the Company shall pay or begin paying a Benefit to a vested Participant during the 60-day period following the Distribution Date. If the Participant has selected annual payments in accordance with Section 6.4(b) below, all payments other than the first payment shall be made on the applicable anniversary of the Distribution Date.
|
6.3
|
Valuation. The value of a Participant's Stock Unit Account for purposes of the Benefit shall be equal to the product of (x) the number of Stock Units in the Participant's Stock Unit Account as of the Distribution Date or the applicable anniversary of the Distribution Date multiplied by (y) the Common Stock Value on the Distribution Date or the applicable anniversary of the Distribution Date, in accordance with Section 6.4 below.
|
6.4
|
Form of Benefit. The Company shall pay a Benefit to a vested Participant in one of the following four (4) forms, as elected by the Participant:
|
|
(a)
|
a lump sum payment, with such payment equal to the value of the Participant's Stock Unit Account as of the Distribution Date: or
|
6.5
|
Change of Form of Benefit. The Participant may change the form of payment of all Stock Units credited to the Stock Unit Account of the Participant and vested prior to January 1, 2005, so long as the change is made at least six (6) months prior to the Distribution Date. With respect to Stock Units credited to the Stock Unit Account of the Participant or vesting on or after January 1, 2005, the Participant must make or have in effect an election as to the form of payment of Stock Units to be credited to the Stock Unit Account of the Participant during the upcoming year no later than December 31 of the preceding year, which election shall be irrevocable for such upcoming year. The Participant may change his or her election for a subsequent year by delivering a new election as to the form of payment to the Company on or before December 31 of the preceding year. An election as to form of payment will remain in effect for future years unless and until changed by the Participant’s timely delivery of a new election as to the form of payment with respect to an upcoming Plan Year. The Participant may not amend or change such an election with respect to any prior year. Notwithstanding the foregoing, on or before December 31, 2007, the Participant may make a one-time change to the Participant’s election as to the form of payment of Stock Units credited to his or her Stock Unit Account as to all years prior to and including 2008, as permitted by the transition relief rules under Code Section 409A and the regulations thereunder.
|
6.6
|
Death of Participant Prior to the Distribution Date. If the Participant's death occurs prior to the Distribution Date, the Company shall pay or begin paying a Benefit to a vested Participant's beneficiary (as designated by the Participant under Section 6.8 below) during the 60-day period following the date of the Participant's death, and if the Participant has selected a form of Benefit under Section 6.4(b) above, the Company shall pay the remaining annual payments on the anniversary of the first payment date as determined under this Section 6.6.
|
6.7
|
Death of Participant Following the Distribution Date. If the Participant's death occurs following the Distribution Date, the Company shall continue to pay the Benefit to the Participant's beneficiary commencing within the 60-day period (as designated by the
|
|
Participant under Section 6.8 below) following the date of the Participant's death in the form of Benefit selected by the Participant in accordance with Section 6.4 above.
|
6.8
|
Designation of Beneficiary. Within thirty days after becoming a Participant, a Participant shall designate a beneficiary to receive the Benefit in the event of the Participant's death. If the Participant does not designate a beneficiary, the beneficiary shall be deemed to be the Participant's spouse on the date of the Participant's death, and if the Participant does not have a spouse on the date of his or her death, then the Participant's estate shall be deemed to be the beneficiary under this Section 6.
|
7.1
|
Withholding Taxes. The Company shall be entitled to withhold from any and all payments made to a Participant under the Plan all federal, state, local and/or other taxes or imposts which the Company determines are required to be so withheld from such payments or by reason of any other payments made to or on behalf of the Participant or for his or her benefit hereunder.
|
7.2
|
No Guarantee of Tax Consequences. No person connected with the Plan in any capacity, including, but not limited to, the Company and any Subsidiary and their directors, officers, agents and employees makes any representation, Commitment, or guarantee that any tax treatment, including, but not limited to, federal, state and local income, estate and gift tax treatment, will be applicable with respect to amounts deferred under the Plan, or paid to or for the benefit of a Participant under the Plan, or that such tax treatment will apply to or be available to a Participant on account of participation in the Plan.
|
8.1
|
Term. The Plan shall be effective as of the Effective Date. The Plan shall remain in effect until the Board terminates the Plan.
|
8.2
|
Termination or Amendment of Plan. The Board may suspend or terminate the Plan at any time with or without prior notice and the Board may amend the Plan at any time with or without prior notice; provided however, that no action authorized by this Section 8.2 shall reduce the balance or adversely affect the vesting of the Stock Unit Account of a Participant, or cause the acceleration of the time or schedule of any payment under the Plan except as provided by regulations under Section 409A of the Code.
|
9.1
|
Adjustments. If there shall be any change in Common Stock through merger, consolidation, reorganization, recapitalization, stock dividend, stock split, reverse stock split, split up, spin-off, combination of shares, exchange of shares, dividend in kind or other like change in capital structure or distribution (other than normal cash dividends) to holders of Common Stock, the number of Stock Units and the Participant's Stock Unit Account shall be adjusted to equitably reflect such change or distribution.
|
9.2
|
Governing Law. The Plan and all actions taken in connection herewith shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law.
|
9.3
|
No Right Title or Interest in Company Assets. Participants shall have no right, title, or interest whatsoever in or to any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. All payments to be made hereunder shall be paid from the general funds of the Company and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts except as expressly set forth in the Plan.
|
9.4
|
No Right to Continued Service. The Participant's rights, if any, to continue to serve the Company as a member of the Board shall not be enlarged or otherwise affected by his or her participation in the Plan.
|
9.5
|
Other Rights. The Plan shall not affect or impair the rights or obligations of the Company or a Participant under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan.
|
9.6
|
Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent. If, however, the Committee determines in its sole discretion that any term or condition of the Plan which is invalid or unenforceable is material to the interests of the Company, the Committee may declare the Plan null and void in its entirety.
|
9.7
|
Incapacity. If the Committee determines that a Participant or a designated beneficiary is unable to care for his or her affairs because of illness or accident or because he or she is a minor, any benefit due the Participant or designated beneficiary may be paid to the Participant's spouse or to any other person deemed by the Committee to have incurred expense for such Participant (including a duly appointed guardian, committee or other legal representative), and any such payment shall be a complete discharge of the Company's obligation hereunder.
|
9.8
|
Transferability of Rights. No Participant or spouse of a Participant shall have any right to encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Participant or such spouse may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be nonassignable and nontransferable, except to the extent required by law.
|
|
Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Participant or the spouse of a Participant shall be null and void and without effect.
|
9.9
|
Entire Document. The Plan, as set forth herein, supersedes any and all prior practices, understandings, agreements, descriptions or other non-written arrangements respecting severance, and written employment or severance contracts signed by the Company.
|
9.10
|
Change in Control. In the case of a Change in Control, the Company, subject to the restrictions in this Section 9.10 and in Section 9.3, shall irrevocably set aside funds in one or more grantor trusts in an amount that is sufficient to pay each Participant the value of the Participant's Stock Unit Account as of the date on which the Change in Control occurs. The foregoing notwithstanding, the Company shall establish no such grantor trust if its assets shall be includable in the income of Participants thereby solely as a result of Section 409A of the Code and the Company shall establish no such grantor trust or set aside funds, revocably or irrevocably, in any such grantor trust in connection with the transactions described in the Agreement and Plan of Merger between the Company and Duke Energy Corporation dated as of January 8, 2011. The obligations and responsibilities of the Company under this Plan shall be assumed by any successor or acquiring corporation, and all of the rights, privileges and benefits of the Participants hereunder shall continue following the Change in Control.
|
9.11
|
Section 409A. Notwithstanding any provision in this Plan to the contrary, this Plan and all rights and benefits of Participants hereunder shall comply with Section 409A of the Code, related regulations and other guidance, and be construed in accordance therewith.
|
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
1.
|
Edwin B. Borden
|
2.
|
Richard L. Daugherty
|
3.
|
Robert L. Jones
|
4.
|
Felton J. Capel
|
5.
|
Charles W. Coker
|
6.
|
Estell C. Lee
|
7.
|
Leslie M. Baker, Jr.
|
8.
|
William O. McCoy
|
9.
|
J. Tylee Wilson
|
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
Page
|
|||||
ARTICLE I
|
|||||
STATEMENT OF PURPOSE
|
1
|
||||
ARTICLE II
|
|||||
DEFINITIONS
|
1
|
||||
2.1
|
Terms
|
1
|
|||
2.2
|
Affiliated Company
|
1
|
|||
2.3
|
Assumed Deferred Vested Pension Benefit
|
1
|
|||
2.4
|
Assumed Early Reetirement Pension Benefit
|
2
|
|||
2.5
|
Assumed Normal Retirement Penison Benefit
|
2
|
|||
2.6
|
Board
|
2
|
|||
2.7
|
Change in Control
|
2
|
|||
2.8
|
Committee
|
3
|
|||
2.9
|
Company
|
3
|
|||
2.10
|
Continuing Director
|
3
|
|||
2.11
|
Designated Beneficiary
|
4
|
|||
2.12
|
Early Retirement Date
|
4
|
|||
2.13
|
Eligible Spouse
|
4
|
|||
2.14
|
Final Average Salary
|
4
|
|||
2.15
|
Normal Retirement Date
|
4
|
|||
2.16
|
Participant
|
4
|
|||
2.17
|
Pension
|
4
|
|||
2.18
|
Plan
|
5
|
|||
2.19
|
Salary
|
5
|
|||
2.20
|
Separation from Service
|
5
|
|||
2.21
|
Service
|
5
|
|||
2.22
|
Social Security Benefit
|
5
|
|||
2.23
|
Spouse’s Pension
|
6
|
|||
2.24
|
Target Early Retirement Benefit
|
6
|
|||
2.25
|
Target Normal Retirement Benefit
|
6
|
|||
2.26
|
Target Pre-Retirement Death Benefit
|
6
|
|||
2.27
|
Target Severance Benefit
|
7
|
|||
ARTICLE III
|
|||||
ELIGIBIITY AND PARTICIPATION
|
7
|
||||
3.1
|
Eligibility
|
7
|
|||
3.2
|
Date of Participation
|
7
|
|||
3.3
|
Duration of Participation
|
7
|
|||
ARTICLE IV
|
|||||
RETIREMENT BENEFITS
|
7
|
||||
4.1
|
Normal Retirement Benefit
|
7
|
|||
4.2
|
Early Retirement Benefit
|
8
|
|||
4.3
|
Surviving Spouse Benefit
|
9
|
|||
4.4
|
Re-employment of Retired Participant
|
9
|
|||
ARTICLE V
|
|||||
PRE-RETIREMENT DEALTH BENEFITS
|
10
|
||||
5.1
|
Eligibiity
|
10
|
|||
5.2
|
Amount
|
10
|
|||
5.3
|
Alternative Benefit
|
10
|
|||
5.4
|
Commencement and Duration
|
10
|
|||
ARTICLE VI
|
|||||
SEVERANCE BENEFITS
|
10
|
||||
6.1
|
Eligiabilty
|
10
|
|||
6.2
|
Amount
|
10
|
|||
6.3
|
Commencement and Duration
|
11
|
|||
6.4
|
Surviving Spouse Benefit
|
11
|
|||
ARTICLE VII
|
|||||
ADMINISTRATION
|
12
|
||||
7.1
|
Committee
|
12
|
|||
7.2
|
Voting
|
12
|
|||
7.3
|
Records
|
12
|
|||
7.4
|
Liability
|
12
|
|||
7.5
|
Expenses
|
12
|
|||
ARTICLE VIII
|
|||||
AMENDMENT AND TERMINATION
|
12
|
||||
ARTICLE IX
|
|||||
MISCELLANEOUS
|
13
|
||||
9.1
|
Non-Alienation of Benefits
|
13
|
|||
9.2
|
No Trust Created
|
13
|
|||
9.3
|
No Employment Agreement
|
13
|
|||
9.4
|
Binding Effect
|
13
|
|||
9.5
|
Suicide
|
13
|
|||
9.6
|
Claims for Benefits
|
13
|
|||
9.7
|
Entire Plan
|
14
|
9.8
|
Change in Control
|
14
|
|||
9.9
|
Acceleration of Payment
|
14
|
|||
ARTICLE X
|
|||||
CONSTRUCTION
|
15
|
||||
10.1
|
Governing Law
|
15
|
|||
10.2
|
Gender
|
15
|
|||
10.3
|
Headings, etc.
|
15
|
|||
10.4
|
Action
|
15
|
|||
By:
|
PROGRESS ENERGY, INC.
/s/ William D. Johnson
William D. Johnson
Chairman, President
and Chief Executive Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Progress Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: November 8, 2011
|
By: /s/ William D. Johnson
|
William D. Johnson
|
|
Chairman, President and Chief Executive Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Progress Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: November 8, 2011
|
By: /s/ Mark F. Mulhern
|
Mark F. Mulhern
|
|
Senior Vice President and Chief Financial Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Carolina Power & Light Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: November 8, 2011
|
By: /s/ Lloyd M. Yates
|
Lloyd M. Yates
|
|
President and Chief Executive Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Carolina Power & Light Company;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: November 8, 2011
|
By: /s/ Mark F. Mulhern
|
Mark F. Mulhern
|
|
Senior Vice President and Chief Financial Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Florida Power Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: November 8, 2011
|
By: /s/ Vincent M. Dolan
|
Vincent M. Dolan
|
|
President and Chief Executive Officer
|
1.
|
I have reviewed this Quarterly Report on Form 10-Q of Florida Power Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: November 8, 2011
|
By: /s/ Mark F. Mulhern
|
Mark F. Mulhern
|
|
Senior Vice President and Chief Financial Officer
|
Unaudited Condensed Consolidated Balance Sheets (Parentheticals) | Sep. 30, 2011 | Dec. 31, 2010 |
---|---|---|
Balance Sheets Parentheticals [Line Items] | ||
Common shares, authorized | 500,000,000 | 500,000,000 |
Common shares, issued | 295,000,000 | 293,000,000 |
Common shares, outstanding | 295,000,000 | 293,000,000 |
PEC | ||
Balance Sheets Parentheticals [Line Items] | ||
Common shares, authorized | 200,000,000 | 200,000,000 |
Common shares, issued | 160,000,000 | 160,000,000 |
Common shares, outstanding | 160,000,000 | 160,000,000 |
PEF | ||
Balance Sheets Parentheticals [Line Items] | ||
Common shares, authorized | 60,000,000 | 60,000,000 |
Common shares, issued | 100 | 100 |
Common shares, outstanding | 100 | 100 |
Organization and Summary of Significant Accounting Policies (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2011 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure Organization And Summary Of Significant Accounting Policies Tables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of excise taxes [Tables] |
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of consolidated variable interest entity [Tables] |
|
Document and Entity Information | 9 Months Ended | |
---|---|---|
Sep. 30, 2011 | Nov. 04, 2011 | |
Document and Entity Information [Line Items] | ||
Entity registrant name | PROGRESS ENERGY INC | |
Entity central index key | 0001094093 | |
Document type | 10-Q | |
Document period end date | Sep. 30, 2011 | |
Amendment flag | false | |
Entity current reporting status | Yes | |
Entity voluntary filers | No | |
Current fiscal year end date | --12-31 | |
Entity filer category | Large Accelerated Filer | |
Entity well known seasoned issuer | Yes | |
Entity common stock shares outstanding | 295,005,362 | |
Document fiscal year focus | 2011 | |
Document fiscal period focus | Q3 | |
PEC | ||
Document and Entity Information [Line Items] | ||
Entity registrant name | Carolina Power & Light Co | |
Entity central index key | 0000017797 | |
Current fiscal year end date | --12-31 | |
Entity filer category | Non-accelerated Filer | |
PEF | ||
Document and Entity Information [Line Items] | ||
Entity registrant name | Florida Power Corp | |
Entity central index key | 0000037637 | |
Current fiscal year end date | --12-31 | |
Entity filer category | Non-accelerated Filer |
Fair Value Disclosures (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2011 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures Tables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Available for sale securities | The following table summarizes our available-for-sale securities at September 30, 2011 and December 31, 2010:
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Available for sale debt securities by contractual maturity | At September 30, 2011, the fair value of our available-for-sale debt securities by contractual maturity was:
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sales of available for sale securities | The following table presents selected information about our sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value measurements- assets and liabilities |
|
Benefit Plans - Contribution and Benefit Payment Expectations (Details) (USD $) In Millions | Sep. 30, 2011 |
---|---|
Contribution And Benefit Payment [Line Items] | |
2011 expected contributions, top of range | $ 350 |
2011 expected contributions, bottom of range | $ 325 |
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Debt and Credit Facilities | 9 Months Ended |
---|---|
Sep. 30, 2011 | |
Debt And Credit Facilities Disclosure [Line Items] | |
Debt and Credit Facilities | 7. DEBT AND CREDIT FACILITIES Material changes, if any, to Progress Energy's, PEC's and PEF's debt and credit facilities and financing activities since December 31, 2010, are as follows. On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due January 15, 2021. The net proceeds, along with available cash on hand, were used to retire the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011. On May 3, 2011, $22 million of the Parent's $500 million revolving credit agreement (RCA) expired, leaving the Parent with total credit commitments of $478 million supported by 14 financial institutions. After the $22 million expiration, our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions. On July 15, 2011, PEF paid at maturity $300 million of its 6.65% First Mortgage Bonds with proceeds from commercial paper borrowings. On August 18, 2011, PEF issued $300 million 3.10% First Mortgage Bonds due August 15, 2021. The net proceeds were used to repay a portion of outstanding short-term debt, of which $300 million was issued to repay PEF's July 15, 2011 maturity. On September 15, 2011, PEC issued $500 million 3.00% First Mortgage Bonds due September 15, 2021. A portion of the net proceeds was used to repay outstanding short-term debt and the remainder was placed in temporary investments for general corporate use as needed, including construction expenditures. On September 30, 2011, the current portion of our long-term debt was $950 million (including $500 million at PEC). We expect to fund the current portion of long-term debt with a combination of cash from operations, commercial paper borrowings and/or long-term debt.
|
PEC | |
Debt And Credit Facilities Disclosure [Line Items] | |
Debt and Credit Facilities | 7. DEBT AND CREDIT FACILITIES Material changes, if any, to Progress Energy's, PEC's and PEF's debt and credit facilities and financing activities since December 31, 2010, are as follows. On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due January 15, 2021. The net proceeds, along with available cash on hand, were used to retire the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011. On May 3, 2011, $22 million of the Parent's $500 million revolving credit agreement (RCA) expired, leaving the Parent with total credit commitments of $478 million supported by 14 financial institutions. After the $22 million expiration, our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions. On July 15, 2011, PEF paid at maturity $300 million of its 6.65% First Mortgage Bonds with proceeds from commercial paper borrowings. On August 18, 2011, PEF issued $300 million 3.10% First Mortgage Bonds due August 15, 2021. The net proceeds were used to repay a portion of outstanding short-term debt, of which $300 million was issued to repay PEF's July 15, 2011 maturity. On September 15, 2011, PEC issued $500 million 3.00% First Mortgage Bonds due September 15, 2021. A portion of the net proceeds was used to repay outstanding short-term debt and the remainder was placed in temporary investments for general corporate use as needed, including construction expenditures. On September 30, 2011, the current portion of our long-term debt was $950 million (including $500 million at PEC). We expect to fund the current portion of long-term debt with a combination of cash from operations, commercial paper borrowings and/or long-term debt.
|
PEF | |
Debt And Credit Facilities Disclosure [Line Items] | |
Debt and Credit Facilities | 7. DEBT AND CREDIT FACILITIES Material changes, if any, to Progress Energy's, PEC's and PEF's debt and credit facilities and financing activities since December 31, 2010, are as follows. On January 21, 2011, the Parent issued $500 million of 4.40% Senior Notes due January 15, 2021. The net proceeds, along with available cash on hand, were used to retire the $700 million outstanding aggregate principal balance of our 7.10% Senior Notes due March 1, 2011. On May 3, 2011, $22 million of the Parent's $500 million revolving credit agreement (RCA) expired, leaving the Parent with total credit commitments of $478 million supported by 14 financial institutions. After the $22 million expiration, our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions. On July 15, 2011, PEF paid at maturity $300 million of its 6.65% First Mortgage Bonds with proceeds from commercial paper borrowings. On August 18, 2011, PEF issued $300 million 3.10% First Mortgage Bonds due August 15, 2021. The net proceeds were used to repay a portion of outstanding short-term debt, of which $300 million was issued to repay PEF's July 15, 2011 maturity. On September 15, 2011, PEC issued $500 million 3.00% First Mortgage Bonds due September 15, 2021. A portion of the net proceeds was used to repay outstanding short-term debt and the remainder was placed in temporary investments for general corporate use as needed, including construction expenditures. On September 30, 2011, the current portion of our long-term debt was $950 million (including $500 million at PEC). We expect to fund the current portion of long-term debt with a combination of cash from operations, commercial paper borrowings and/or long-term debt.
|
Benefit Plans (Tables) | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Benefit Plans Tables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Tables] | The components of the net periodic benefit cost for the respective Progress Registrants for the three months ended September 30 were:
The components of the net periodic benefit cost for the respective Progress Registrants for the nine months ended September 30 were:
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Income Taxes (Details) (USD $) In Millions | 9 Months Ended | |
---|---|---|
Sep. 30, 2011 | Dec. 31, 2010 | |
Net deferred income tax classification | ||
Deferred tax assets | $ 285 | $ 156 |
Changes to unrecognized tax benefits | ||
Amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate | 6 | |
Unrecognized tax benefits at beginning of period | 176 | |
Unrecognized tax benefits at end of period | 176 | |
Open tax years by jurisdiction | Our federal tax years are open for examination from 2007 forward, and our open state tax years in our major jurisdictions are generally from 2003 forward. | |
Interest and penalties accrued | $ 19 | $ 45 |
Equity - Common Stock (Details) (USD $) In Millions | 3 Months Ended | 9 Months Ended | |||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | Dec. 31, 2010 | |
Common Stock [Details] | |||||
Common shares, authorized | 500 | 500 | 500 | ||
Common shares, outstanding | 295 | 295 | 293 | ||
Total issuances - shares | 0.3 | 0.3 | 1.7 | 11.8 | |
Issuance through 401(k) and or IPP - shares | 0 | 0.3 | 0 | 11.0 | |
Total issuances - net proceeds | $ 16 | $ 14 | $ 42 | $ 419 | |
Issuances through 401(k) and or IPP - net proceeds | $ 0 | $ 13 | $ 1 | $ 418 |
Equity (Tables) | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Common stock |
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Comprehensive income |
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Reconciliation of total equity |
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Risk Management Activities and Derivative Transactions | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Risk Management Activities And Derivative Transactions Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management Activities And Derivative Transactions | 12. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. A. COMMODITY DERIVATIVES GENERAL Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. ECONOMIC DERIVATIVES Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2011 and 2012. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause. Certain 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. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures. Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $112 million and $164 million on the Progress Energy Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, Progress Energy had 339.4 million MMBtu notional of natural gas and 12.3 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases. PEC had a cash collateral asset included in prepayments and other current assets of $14 million and $24 million on the PEC Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEC had 98.4 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases. PEF's cash collateral asset included in derivative collateral posted was $98 million and $140 million on the PEF Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEF had 241.0 million MMBtu notional of natural gas and 12.3 million gallons notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases. B. INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates. CASH FLOW HEDGES At September 30, 2011, all open interest rate hedges will reach their mandatory termination dates in approximately two years. At September 30, 2011, including amounts related to terminated hedges, we had $140 million of after-tax losses, including $70 million and $26 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $12 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities and changes in market value of currently open forward starting swaps. At December 31, 2010, including amounts related to terminated hedges, we had $63 million of after-tax losses, including $33 million and $4 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps. At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. At September 30, 2011, Progress Energy had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF. FAIR VALUE HEDGES For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At September 30, 2011, and December 31, 2010, neither we nor the Utilities had any outstanding positions in such contracts. C. CONTINGENT FEATURES Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company's credit rating with Moody's Investors Service, Inc. (Moody's), Standard & Poor's Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions. In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody's, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions. The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $377 million at September 30, 2011, for which Progress Energy has posted collateral of $112 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, Progress Energy would have been required to post an additional $265 million of collateral with its counterparties. The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $116 million at September 30, 2011, for which PEC has posted collateral of $14 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, PEC would have been required to post an additional $102 million of collateral with its counterparties. The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $261 million at September 30, 2011, for which PEF has posted collateral of $98 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on September 30, 2011, PEF would have been required to post an additional $163 million of collateral with its counterparties. D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION PROGRESS ENERGY
The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the three months ended September 30, 2011 and 2010:
The following tables present the effect of derivative instruments on OCI (See Note 5C) and the Consolidated Statements of Income for the nine months ended September 30, 2011 and 2010:
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Risk Management Activities And Derivative Transactions Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management Activities And Derivative Transactions | 12. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. A. COMMODITY DERIVATIVES GENERAL Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. ECONOMIC DERIVATIVES Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2011 and 2012. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause. Certain 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. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures. Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $112 million and $164 million on the Progress Energy Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, Progress Energy had 339.4 million MMBtu notional of natural gas and 12.3 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases. PEC had a cash collateral asset included in prepayments and other current assets of $14 million and $24 million on the PEC Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEC had 98.4 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases. PEF's cash collateral asset included in derivative collateral posted was $98 million and $140 million on the PEF Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEF had 241.0 million MMBtu notional of natural gas and 12.3 million gallons notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases. B. INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates. CASH FLOW HEDGES At September 30, 2011, all open interest rate hedges will reach their mandatory termination dates in approximately two years. At September 30, 2011, including amounts related to terminated hedges, we had $140 million of after-tax losses, including $70 million and $26 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $12 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities and changes in market value of currently open forward starting swaps. At December 31, 2010, including amounts related to terminated hedges, we had $63 million of after-tax losses, including $33 million and $4 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps. At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. At September 30, 2011, Progress Energy had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF. FAIR VALUE HEDGES For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At September 30, 2011, and December 31, 2010, neither we nor the Utilities had any outstanding positions in such contracts. C. CONTINGENT FEATURES Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company's credit rating with Moody's Investors Service, Inc. (Moody's), Standard & Poor's Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions. In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody's, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions. The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $377 million at September 30, 2011, for which Progress Energy has posted collateral of $112 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, Progress Energy would have been required to post an additional $265 million of collateral with its counterparties. The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $116 million at September 30, 2011, for which PEC has posted collateral of $14 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, PEC would have been required to post an additional $102 million of collateral with its counterparties. The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $261 million at September 30, 2011, for which PEF has posted collateral of $98 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on September 30, 2011, PEF would have been required to post an additional $163 million of collateral with its counterparties. D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION
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Risk Management Activities And Derivative Transactions Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management Activities And Derivative Transactions | 12. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. We minimize such risk by performing credit and financial reviews using a combination of financial analysis and publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. A. COMMODITY DERIVATIVES GENERAL Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value. ECONOMIC DERIVATIVES Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2011 and 2012. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause. Certain 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. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures. Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $112 million and $164 million on the Progress Energy Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, Progress Energy had 339.4 million MMBtu notional of natural gas and 12.3 million gallons notional of fuel oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases. PEC had a cash collateral asset included in prepayments and other current assets of $14 million and $24 million on the PEC Consolidated Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEC had 98.4 million MMBtu notional of natural gas related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas purchases. PEF's cash collateral asset included in derivative collateral posted was $98 million and $140 million on the PEF Balance Sheets at September 30, 2011 and December 31, 2010, respectively. At September 30, 2011, PEF had 241.0 million MMBtu notional of natural gas and 12.3 million gallons notional of oil related to outstanding commodity derivative swaps that were entered into to hedge forecasted natural gas and oil purchases. B. INTEREST RATE DERIVATIVES – FAIR VALUE OR CASH FLOW HEDGES We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. Our cash flow hedging strategies are primarily accomplished through the use of forward starting swaps and our fair value hedging strategies are primarily accomplished through the use of fixed-to-floating swaps. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the exposure in these transactions is the cost of replacing the agreements at current market rates. CASH FLOW HEDGES At September 30, 2011, all open interest rate hedges will reach their mandatory termination dates in approximately two years. At September 30, 2011, including amounts related to terminated hedges, we had $140 million of after-tax losses, including $70 million and $26 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $12 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities and changes in market value of currently open forward starting swaps. At December 31, 2010, including amounts related to terminated hedges, we had $63 million of after-tax losses, including $33 million and $4 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps. At December 31, 2010, Progress Energy had $1.050 billion notional of open forward starting swaps, including $350 million at PEC and $200 million at PEF. At September 30, 2011, Progress Energy had $500 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF. FAIR VALUE HEDGES For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. At September 30, 2011, and December 31, 2010, neither we nor the Utilities had any outstanding positions in such contracts. C. CONTINGENT FEATURES Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company's credit rating with Moody's Investors Service, Inc. (Moody's), Standard & Poor's Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions. In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody's, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions. The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $377 million at September 30, 2011, for which Progress Energy has posted collateral of $112 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, Progress Energy would have been required to post an additional $265 million of collateral with its counterparties. The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $116 million at September 30, 2011, for which PEC has posted collateral of $14 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at September 30, 2011, PEC would have been required to post an additional $102 million of collateral with its counterparties. The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $261 million at September 30, 2011, for which PEF has posted collateral of $98 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered on September 30, 2011, PEF would have been required to post an additional $163 million of collateral with its counterparties. D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION
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New Accounting Standards | 9 Months Ended |
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Sep. 30, 2011 | |
Schedule Of New Accounting Pronouncements And Changes In Accounting Principles Disclosure [Line Items] | |
Description Of New Accounting Pronouncements [Text Block] | 3. NEW ACCOUNTING STANDARDS FAIR VALUE MEASUREMENT AND DISCLOSURES In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” which amends Accounting Standards Codification (ASC) 820 to clarify certain existing disclosure requirements and to require a number of additional disclosures, including amounts and reasons for significant transfers between the three levels of the fair value hierarchy, and presentation of certain information in the reconciliation of recurring Level 3 measurements on a gross basis. ASU 2010-06 was effective for us on January 1, 2010, with certain disclosures effective January 1, 2011. The adoption of ASU 2010-06 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities' financial position, results of operations, or cash flows. In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends ASC 820 to develop a single, converged fair value framework between U.S. GAAP and IFRS. ASU 2011-04 is effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 will result in changes in certain fair value measurement principles, as well as additional disclosure in the notes to the financial statements. However, the impact of adoption is not expected to be significant to our or the Utilities' financial position, results of operations, or cash flows. GOODWILL IMPAIRMENT TESTING In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it is determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 is effective for us on January 1, 2012. The adoption of ASU 2011-08 will give us the option, at our normal goodwill testing date, to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The impact of the adoption is not expected to be significant to our or the Utilities' financial position, results of operations, or cash flows. |
PEC | |
Schedule Of New Accounting Pronouncements And Changes In Accounting Principles Disclosure [Line Items] | |
Description Of New Accounting Pronouncements [Text Block] | 3. NEW ACCOUNTING STANDARDS FAIR VALUE MEASUREMENT AND DISCLOSURES In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” which amends Accounting Standards Codification (ASC) 820 to clarify certain existing disclosure requirements and to require a number of additional disclosures, including amounts and reasons for significant transfers between the three levels of the fair value hierarchy, and presentation of certain information in the reconciliation of recurring Level 3 measurements on a gross basis. ASU 2010-06 was effective for us on January 1, 2010, with certain disclosures effective January 1, 2011. The adoption of ASU 2010-06 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities' financial position, results of operations, or cash flows. In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends ASC 820 to develop a single, converged fair value framework between U.S. GAAP and IFRS. ASU 2011-04 is effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 will result in changes in certain fair value measurement principles, as well as additional disclosure in the notes to the financial statements. However, the impact of adoption is not expected to be significant to our or the Utilities' financial position, results of operations, or cash flows. GOODWILL IMPAIRMENT TESTING In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it is determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 is effective for us on January 1, 2012. The adoption of ASU 2011-08 will give us the option, at our normal goodwill testing date, to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The impact of the adoption is not expected to be significant to our or the Utilities' financial position, results of operations, or cash flows. |
PEF | |
Schedule Of New Accounting Pronouncements And Changes In Accounting Principles Disclosure [Line Items] | |
Description Of New Accounting Pronouncements [Text Block] | 3. NEW ACCOUNTING STANDARDS FAIR VALUE MEASUREMENT AND DISCLOSURES In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” which amends Accounting Standards Codification (ASC) 820 to clarify certain existing disclosure requirements and to require a number of additional disclosures, including amounts and reasons for significant transfers between the three levels of the fair value hierarchy, and presentation of certain information in the reconciliation of recurring Level 3 measurements on a gross basis. ASU 2010-06 was effective for us on January 1, 2010, with certain disclosures effective January 1, 2011. The adoption of ASU 2010-06 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities' financial position, results of operations, or cash flows. In May 2011, the FASB issued ASU 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends ASC 820 to develop a single, converged fair value framework between U.S. GAAP and IFRS. ASU 2011-04 is effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 will result in changes in certain fair value measurement principles, as well as additional disclosure in the notes to the financial statements. However, the impact of adoption is not expected to be significant to our or the Utilities' financial position, results of operations, or cash flows. GOODWILL IMPAIRMENT TESTING In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it is determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 is effective for us on January 1, 2012. The adoption of ASU 2011-08 will give us the option, at our normal goodwill testing date, to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The impact of the adoption is not expected to be significant to our or the Utilities' financial position, results of operations, or cash flows. |
Income Taxes | 9 Months Ended |
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Sep. 30, 2011 | |
Income Taxes Disclosure [Line Items] | |
Income Taxes | 9. INCOME TAXES PROGRESS ENERGY We and our subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Our federal tax years are open for examination from 2007 forward, and our open state tax years in our major jurisdictions are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns. At September 30, 2011 and December 31, 2010, our liability for unrecognized tax benefits was $176 million. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $6 million at September 30, 2011. At September 30, 2011 and December 31, 2010, we had accrued $19 million and $45 million, respectively, for interest and penalties, which were included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets. The decrease in interest and penalties was due to the completion of the examination of the 2004 and 2005 tax returns previously discussed.
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PEC | |
Income Taxes Disclosure [Line Items] | |
Income Taxes | PEC We file consolidated federal and state income tax returns that include PEC. In addition, PEC files stand-alone tax returns in various state jurisdictions. PEC's federal tax years are open for examination from 2007 forward, and PEC's open state tax years in our major jurisdictions are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns. At September 30, 2011 and December 31, 2010, PEC's liability for unrecognized tax benefits was $79 million and $74 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $4 million at September 30, 2011. At September 30, 2011 and December 31, 2010, PEC had accrued $8 million and $14 million, respectively, for interest and penalties, which were included in interest accrued and other liabilities and deferred credits on the Consolidated Balance Sheets. The decrease in interest and penalties was due to the completion of the examination of the 2004 and 2005 tax returns previously discussed. |
PEF | |
Income Taxes Disclosure [Line Items] | |
Income Taxes | PEF We file consolidated federal and state income tax returns that include PEF. PEF's federal tax years are open for examination from 2007 forward and PEF's open state tax years are generally from 2003 forward. During the three months ended September 30, 2011, the IRS completed its examination of the 2004 and 2005 tax returns. At September 30, 2011 and December 31, 2010, PEF's liability for unrecognized tax benefits was $87 million and $99 million, respectively. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for income from continuing operations was $2 million at September 30, 2011. At September 30, 2011, PEF had accrued $7 million for interest and penalties, which were included in other current assets and other liabilities and deferred credits on the Balance Sheets. At December 31, 2010, PEF had accrued $29 million for interest and penalties, which were included in interest accrued and other assets and deferred debits on the Balance Sheets. The decrease in interest and penalties was due to the completion of the examination of the 2004 and 2005 tax returns previously discussed.
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Environmental Matters | 14. ENVIRONMENTAL MATTERS We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated. A. HAZARDOUS AND SOLID WASTE The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter. 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 liabilities. 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 party (PRP) groups as described below in greater detail. 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. 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. We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M expense on the Income Statements to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future. The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:
PROGRESS ENERGY In addition to the Utilities' sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 15B). PEC PEC has recorded a minimum estimated total remediation cost for its remaining MGP sites based upon its historical experience with remediation of its MGP sites remediated to date. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site in Raleigh, N.C. (Ward). The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA's past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At September 30, 2011 and December 31, 2010, PEC's recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. In June 2010, the court entered a case management order and discovery is proceeding. The court also set a trial date for May 7, 2012. The outcome of these matters cannot be predicted. In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA's estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA's past expenditures in addressing conditions at the site. On September 29, 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. It is not possible at this time to reasonably estimate the total amount of PEC's obligation, if any, for Ward OU1 and Ward OU2. PEF The accruals for PEF's MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of a population of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed these distribution transformer sites and substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC. B. AIR AND WATER QUALITY We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations include the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the CAIR. In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court's prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for NOx and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals' decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of NOx and SO2 emissions in addition to particulate matter emissions for PEF's BART-eligible units, because Florida will no longer be subject to the annual emissions provisions. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. We are currently evaluating the impacts of the CSAPR. In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it would develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On October 21, 2011, the EPA requested the U.S. District Court for the District of Columbia to extend the deadline for the final rule to December 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following the conclusion of the 90-day public comment period, the EPA has requested to issue a final rule in December 2011. In addition, North Carolina adopted a state-specific mercury requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of the EPA's proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted. To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 4B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter. We account for emission allowances as inventory using the average cost method. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs effective January 1, 2012. SO2 emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. NOx allowances cannot be utilized to comply with other requirements. Therefore, NOx allowances that are not expected to be used in 2011 have been classified as obsolete inventory. PEC had an immaterial amount of NOx emission allowances. During the three and nine months ended September 30, 2011, PEF reduced the value of its NOx allowance inventory by $23 million, which is the remaining amount of NOx allowances that are not expected to be used in 2011. PEF believes the purchases of NOx emission allowances to meet the requirements of the CAIR were prudent and expects to recover the retail portion of the costs of these allowances through its ECRC. Accordingly, PEF recorded a $22 million regulatory asset for the retail portion of its NOx allowances. Therefore, there was no material impact to PEF's results of operations for the reduction in value of its NOx allowance inventory. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Environmental Matters | 14. ENVIRONMENTAL MATTERS We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated. A. HAZARDOUS AND SOLID WASTE The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter. 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 liabilities. 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 party (PRP) groups as described below in greater detail. 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. 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. We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M expense on the Income Statements to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future. The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:
PEC PEC has recorded a minimum estimated total remediation cost for its remaining MGP sites based upon its historical experience with remediation of its MGP sites remediated to date. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site in Raleigh, N.C. (Ward). The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA's past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At September 30, 2011 and December 31, 2010, PEC's recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. In June 2010, the court entered a case management order and discovery is proceeding. The court also set a trial date for May 7, 2012. The outcome of these matters cannot be predicted. In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for the operable unit for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA's estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA's past expenditures in addressing conditions at the site. On September 29, 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. It is not possible at this time to reasonably estimate the total amount of PEC's obligation, if any, for Ward OU1 and Ward OU2. B. AIR AND WATER QUALITY We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations include the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the CAIR. In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court's prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for NOx and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals' decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of NOx and SO2 emissions in addition to particulate matter emissions for PEF's BART-eligible units, because Florida will no longer be subject to the annual emissions provisions. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. We are currently evaluating the impacts of the CSAPR. In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it would develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On October 21, 2011, the EPA requested the U.S. District Court for the District of Columbia to extend the deadline for the final rule to December 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following the conclusion of the 90-day public comment period, the EPA has requested to issue a final rule in December 2011. In addition, North Carolina adopted a state-specific mercury requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of the EPA's proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted. To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 4B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter. We account for emission allowances as inventory using the average cost method. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs effective January 1, 2012. SO2 emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. NOx allowances cannot be utilized to comply with other requirements. Therefore, NOx allowances that are not expected to be used in 2011 have been classified as obsolete inventory. PEC had an immaterial amount of NOx emission allowances. During the three and nine months ended September 30, 2011, PEF reduced the value of its NOx allowance inventory by $23 million, which is the remaining amount of NOx allowances that are not expected to be used in 2011. PEF believes the purchases of NOx emission allowances to meet the requirements of the CAIR were prudent and expects to recover the retail portion of the costs of these allowances through its ECRC. Accordingly, PEF recorded a $22 million regulatory asset for the retail portion of its NOx allowances. Therefore, there was no material impact to PEF's results of operations for the reduction in value of its NOx allowance inventory. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Enviromental Matters Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters | 14. ENVIRONMENTAL MATTERS We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated. A. HAZARDOUS AND SOLID WASTE The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal as hazardous waste. The other option would have the EPA set performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residues that are recycled. A final rule is expected in 2012. Compliance plans and estimated costs to meet the requirements of new regulations will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter. 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 liabilities. 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 party (PRP) groups as described below in greater detail. 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. 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. We measure our liability for environmental sites based on available evidence, including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites in O&M expense on the Income Statements to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future. The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:
PEF The accruals for PEF's MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. The maximum amount of the range for all the sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of a population of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed these distribution transformer sites and substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC. B. AIR AND WATER QUALITY We are subject to various current federal, state and local environmental compliance laws and regulations governing air and water quality, resulting in capital expenditures and increased O&M expense. These compliance laws and regulations include the Clean Air Interstate Rule (CAIR), the Clean Air Visibility Rule (CAVR), the North Carolina Clean Smokestacks Act, enacted in June 2002 (Clean Smokestacks Act) and mercury air regulation. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the Clean Smokestacks Act. The air quality controls installed to comply with nitrogen oxides (NOx) requirements under certain sections of the Clean Air Act and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address the CAIR requirements for NOx for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the CAIR. In 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals) initially vacated the CAIR in its entirety and subsequently remanded the rule without vacating it for the EPA to conduct further proceedings consistent with the court's prior opinion. In 2010, the EPA published the proposed Clean Air Transport Rule, which was the regulatory program proposed to replace the CAIR. On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) as the final version of the proposed Clean Air Transport Rule. The CSAPR replaces the CAIR effective January 1, 2012. The CSAPR contains new emissions trading programs for NOx and sulfur dioxide (SO2) emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required. Florida is subject only to the NOx ozone season program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe both PEC and PEF are relatively well positioned to comply with the CSAPR. Because of the D.C. Court of Appeals' decision that remanded the CAIR, implementation of the CAIR fulfilled best available retrofit technology (BART) for NOx and SO2 for BART-affected units under the CAVR. Under subsequent implementation of CSAPR, CAVR compliance eventually will require consideration of NOx and SO2 emissions in addition to particulate matter emissions for PEF's BART-eligible units, because Florida will no longer be subject to the annual emissions provisions. We are assessing the potential impact of BART and its implications with respect to our plans and estimated costs to comply with the CAVR. We are currently evaluating the impacts of the CSAPR. In 2008, the D.C. Court of Appeals vacated the Clean Air Mercury Rule (CAMR). As a result, the EPA subsequently announced that it would develop a maximum achievable control technology (MACT) standard. The U.S. District Court for the District of Columbia issued an order requiring the EPA to issue a final MACT standard for power plants by November 16, 2011. On October 21, 2011, the EPA requested the U.S. District Court for the District of Columbia to extend the deadline for the final rule to December 16, 2011. On March 16, 2011, the EPA issued its proposed MACT standards for coal-fired and oil-fired electric steam generating units (EGU MACT), and the proposed EGU MACT was formally published in the Federal Register on May 3, 2011. The proposed EGU MACT contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units. Following the conclusion of the 90-day public comment period, the EPA has requested to issue a final rule in December 2011. In addition, North Carolina adopted a state-specific mercury requirement. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. We are currently evaluating the impact of the EPA's proposed EGU MACT standard and the North Carolina state-specific requirement. The outcome of these matters cannot be predicted. To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at Crystal River Units No. 4 and No. 5 (CR4 and CR5), which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal River Units No. 1 and No. 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 will be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 4B, major construction activities for Levy are being postponed until after the NRC issues the Levy COL. As required, PEF has advised the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter. We account for emission allowances as inventory using the average cost method. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits. We value inventory of the Utilities at historical cost consistent with ratemaking treatment. As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs effective January 1, 2012. SO2 emission allowances will be utilized by the Utilities to comply with existing Clean Air Act requirements. NOx allowances cannot be utilized to comply with other requirements. Therefore, NOx allowances that are not expected to be used in 2011 have been classified as obsolete inventory. PEC had an immaterial amount of NOx emission allowances. During the three and nine months ended September 30, 2011, PEF reduced the value of its NOx allowance inventory by $23 million, which is the remaining amount of NOx allowances that are not expected to be used in 2011. PEF believes the purchases of NOx emission allowances to meet the requirements of the CAIR were prudent and expects to recover the retail portion of the costs of these allowances through its ECRC. Accordingly, PEF recorded a $22 million regulatory asset for the retail portion of its NOx allowances. Therefore, there was no material impact to PEF's results of operations for the reduction in value of its NOx allowance inventory. |
Contingent Value Obligations | 9 Months Ended |
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Sep. 30, 2011 | |
Contingent Value Obligations Disclosure [Abstract] | |
Contingent value obligations | 10. CONTINGENT VALUE OBLIGATIONS In connection with the acquisition of Florida Progress Corporation (Florida Progress) during 2000, the Parent issued 98.6 million CVOs. Each CVO represents the right of the holder to receive contingent payments based on the performance of four coal-based solid synthetic fuels limited liability companies purchased by subsidiaries of Florida Progress in October 1999. All of our synthetic fuels businesses were abandoned and all operations ceased as of December 31, 2007 (See Note 15 of the 2010 Form 10-K). On June 10, 2011, Davidson Kempner Partners, M.H. Davidson & Co., Davidson Kempner Institutional Partners, L.P., and Davidson Kempner International, Ltd. (jointly, Davidson Kempner) filed a lawsuit against us (see Note 15C) related to their ownership of CVOs. On October 3, 2011, we entered a settlement agreement and release with Davidson Kempner under which the parties mutually released all claims related to the CVOs and we purchased all of Davidson Kempner's CVOs at a negotiated purchase price of $0.75 per CVO. The settlement agreement also contemplated a tender offer to remaining CVO holders at the same purchase price. Accordingly, we determined the purchase price included in the settlement agreement represented the fair value of the CVOs at September 30, 2011 (see Note 8). We commenced the tender offer in early November. The unrealized loss due to the change in fair value is recorded in other, net on the Consolidated Statements of Income. At September 30, 2011, the CVO liability included in other current liabilities on our Consolidated Balance Sheets was $74 million, and at December 31, 2010, the CVO liability included in other liabilities and deferred credits on our Consolidated Balance Sheets was $15 million. |
Merger Agreement (Details) (USD $) In Millions, except Share data | 3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | |
Business Combinations [Abstract] | ||||
Business Acquisition, Date Of Acquisition Agreement | January 8, 2011 | |||
Merger, Description | Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction (the Merger) and continue as a wholly owned subsidiary of Duke Energy. | |||
Merger share exchange ratio | 2.6125 | 2.6125 | ||
Merger Share Exchange Ratio, Adjusted | 0.87083 | 0.87083 | ||
Settlement Agreement, Date | September 2, 2011 | |||
Settlement Agreement, Description | Progress Energy and Duke Energy will guarantee $650 million in fuel cost savings for customers in North Carolina and South Carolina between 2012 and 2016, maintain their current level of community support for the next four years, and provide $15 million for low-income energy assistance and workforce development. The parties also agreed that direct merger-related expenses would not be recovered from customers. Recovery of merger-related employee severance costs can be requested separately. | |||
Settlement Agreement, Fuel Savings | $ 650 | $ 650 | ||
Loss Contingencies [Line Items] | ||||
Loss Contingency Estimate Of Possible Loss | 14 | 14 | ||
Loss Contingency Unrecorded Estimate Of Possible Loss | 16 | 16 | ||
Settlement Agreement, Low Income And Workforce Assistance | 15 | 15 | ||
Merger and integration costs, net of tax | $ 15 | $ 0 | $ 36 | $ 0 |
Fair Value Disclosures | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value Disclosures [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures | 8. FAIR VALUE DISCLOSURES A. DEBT AND INVESTMENTS PROGRESS ENERGY DEBT The carrying amount of our long-term debt, including current maturities, was $12.940 billion and $12.642 billion at September 30, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $15.1 billion and $14.0 billion at September 30, 2011 and December 31, 2010, respectively. INVESTMENTS Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities' nuclear plants as discussed in Note 4C of the 2010 Form 10-K. Nuclear decommissioning trust (NDT) funds are presented on the Consolidated Balance Sheets at fair value. In addition to the NDT funds, we hold other debt investments in certain benefit trusts classified as available-for-sale, which are included in miscellaneous other property and investments on the Consolidated Balance Sheets at fair value. The following table summarizes our available-for-sale securities at September 30, 2011 and December 31, 2010:
The NDT funds and other available-for-sale debt investments held in certain benefit trusts are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and unrealized gains for 2011 and 2010 relate to the NDT funds. The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $266 million and $195 million, respectively. At September 30, 2011, the fair value of our available-for-sale debt securities by contractual maturity was:
The following table presents selected information about our sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.
Proceeds were primarily related to NDT funds. Some of our benefit investment trusts are managed by third-party investment managers who have the right to sell securities without our authorization. Losses for investments in those benefit investment trusts were not material. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, our other securities had no investments in a continuous loss position for greater than 12 months. PEC DEBT The carrying amount of PEC's long-term debt, including current maturities, was $4.193 billion and $3.693 billion at September 30, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.7 billion and $4.0 billion at September 30, 2011 and December 31, 2010, respectively. INVESTMENTS Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC's nuclear plants as discussed in Note 4C of the 2010 Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value. The following table summarizes PEC's available-for-sale securities at September 30, 2011 and December 31, 2010:
The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds. The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $142 million and $104 million, respectively. At September 30, 2011, the fair value of PEC's available-for-sale debt securities by contractual maturity was:
The following table presents selected information about PEC's sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.
PEC's proceeds were primarily related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, PEC did not have any other securities. PEF DEBT The carrying amount of PEF's long-term debt, including current maturities, was $4.482 billion at September 30, 2011 and December 31, 2010. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $5.4 billion and $5.0 billion at September 30, 2011 and December 31, 2010, respectively. INVESTMENTS Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF's nuclear plant as discussed in Note 4C of the 2010 Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.
The following table summarizes PEF's available-for-sale securities at September 30, 2011 and December 31, 2010:
The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds. The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $124 million and $87 million, respectively. At September 30, 2011, the fair value of PEF's available-for-sale debt securities by contractual maturity was:
The following table presents selected information about PEF's sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.
PEF's proceeds were related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, PEF did not have any other securities. B. FAIR VALUE MEASUREMENTS GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient. GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets. Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available. Certain assets and liabilities, including long-lived assets, were measured at fair value on a nonrecurring basis. There were no significant fair value measurement losses recognized for such assets and liabilities in the periods reported. These fair value measurements fall within Level 3 of the hierarchy discussed above. The following tables set forth, by level within the fair value hierarchy, our and the Utilities' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities' credit risk on our liabilities. Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 12 for discussion of risk management activities and derivative transactions. NDT funds reflect the assets of the Utilities' nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2. Other marketable securities primarily represent available-for-sale debt securities used to fund certain employee benefit costs. Contingent Value Obligations (CVOs), which are derivatives, are discussed further in Note 10. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and we have classified CVOs as Level 3. The CVOs were previously recorded at fair value based on quoted prices from a less-than-active market and classified as Level 2. Transfers in (out) of Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher Level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. There were no significant transfers in (out) of Levels 1, 2 and 3 during the period other than the CVO transfer previously discussed. Transfers into and out of each Level are measured at the end of the period. A reconciliation of changes in the fair value of our and the Utilities' derivative liabilities for CVOs and commodities, as applicable, classified as Level 3 in the fair value hierarchy for the periods ended September 30 follows:
Substantially all unrealized gains and losses on the Utilities' derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Unrealized losses on the change in fair value of our CVOs are discussed in Note 12. There were no Level 3 purchases, sales, issuances or settlements during the period.
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PEC | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures | 8. FAIR VALUE DISCLOSURES A. DEBT AND INVESTMENTS PEC DEBT The carrying amount of PEC's long-term debt, including current maturities, was $4.193 billion and $3.693 billion at September 30, 2011 and December 31, 2010, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $4.7 billion and $4.0 billion at September 30, 2011 and December 31, 2010, respectively. INVESTMENTS Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC's nuclear plants as discussed in Note 4C of the 2010 Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value. The following table summarizes PEC's available-for-sale securities at September 30, 2011 and December 31, 2010:
The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds. The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $142 million and $104 million, respectively. At September 30, 2011, the fair value of PEC's available-for-sale debt securities by contractual maturity was:
The following table presents selected information about PEC's sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.
PEC's proceeds were primarily related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, PEC did not have any other securities. B. FAIR VALUE MEASUREMENTS GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient. GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets. Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available. Certain assets and liabilities, including long-lived assets, were measured at fair value on a nonrecurring basis. There were no significant fair value measurement losses recognized for such assets and liabilities in the periods reported. These fair value measurements fall within Level 3 of the hierarchy discussed above. The following tables set forth, by level within the fair value hierarchy, our and the Utilities' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities' credit risk on our liabilities. Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 12 for discussion of risk management activities and derivative transactions. NDT funds reflect the assets of the Utilities' nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2. Other marketable securities primarily represent available-for-sale debt securities used to fund certain employee benefit costs. Contingent Value Obligations (CVOs), which are derivatives, are discussed further in Note 10. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and we have classified CVOs as Level 3. The CVOs were previously recorded at fair value based on quoted prices from a less-than-active market and classified as Level 2. Transfers in (out) of Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher Level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. There were no significant transfers in (out) of Levels 1, 2 and 3 during the period other than the CVO transfer previously discussed. Transfers into and out of each Level are measured at the end of the period. A reconciliation of changes in the fair value of our and the Utilities' derivative liabilities for CVOs and commodities, as applicable, classified as Level 3 in the fair value hierarchy for the periods ended September 30 follows:
Substantially all unrealized gains and losses on the Utilities' derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Unrealized losses on the change in fair value of our CVOs are discussed in Note 12. There were no Level 3 purchases, sales, issuances or settlements during the period.
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PEF | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures | 8. FAIR VALUE DISCLOSURES A. DEBT AND INVESTMENTS PEF DEBT The carrying amount of PEF's long-term debt, including current maturities, was $4.482 billion at September 30, 2011 and December 31, 2010. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $5.4 billion and $5.0 billion at September 30, 2011 and December 31, 2010, respectively. INVESTMENTS Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF's nuclear plant as discussed in Note 4C of the 2010 Form 10-K. The NDT funds are presented on the Balance Sheets at fair value. The following table summarizes PEF's available-for-sale securities at September 30, 2011 and December 31, 2010:
The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes unrealized gains and losses for the NDT funds based on the original cost of the trust investments. All of the unrealized losses and gains for 2011 and 2010 relate to the NDT funds. The aggregate fair value of investments that related to the September 30, 2011 and December 31, 2010 unrealized losses was $124 million and $87 million, respectively. At September 30, 2011, the fair value of PEF's available-for-sale debt securities by contractual maturity was:
The following table presents selected information about PEF's sales of available-for-sale securities during the three and nine months ended September 30, 2011 and 2010. Realized gains and losses were determined on a specific identification basis.
PEF's proceeds were related to NDT funds. Other securities are evaluated on an individual basis to determine if a decline in fair value below the carrying value is other-than-temporary. At September 30, 2011 and December 31, 2010, PEF did not have any other securities. B. FAIR VALUE MEASUREMENTS GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient. GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets. Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available. Certain assets and liabilities, including long-lived assets, were measured at fair value on a nonrecurring basis. There were no significant fair value measurement losses recognized for such assets and liabilities in the periods reported. These fair value measurements fall within Level 3 of the hierarchy discussed above. The following tables set forth, by level within the fair value hierarchy, our and the Utilities' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities' credit risk on our liabilities. Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Other derivatives are valued utilizing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. See Note 12 for discussion of risk management activities and derivative transactions. NDT funds reflect the assets of the Utilities' nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2. Other marketable securities primarily represent available-for-sale debt securities used to fund certain employee benefit costs. Contingent Value Obligations (CVOs), which are derivatives, are discussed further in Note 10. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and we have classified CVOs as Level 3. The CVOs were previously recorded at fair value based on quoted prices from a less-than-active market and classified as Level 2. Transfers in (out) of Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher Level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. There were no significant transfers in (out) of Levels 1, 2 and 3 during the period other than the CVO transfer previously discussed. Transfers into and out of each Level are measured at the end of the period. A reconciliation of changes in the fair value of our and the Utilities' derivative liabilities for CVOs and commodities, as applicable, classified as Level 3 in the fair value hierarchy for the periods ended September 30 follows:
Substantially all unrealized gains and losses on the Utilities' derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Unrealized losses on the change in fair value of our CVOs are discussed in Note 12. There were no Level 3 purchases, sales, issuances or settlements during the period.
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Environmental Matters (Details) (USD $) In Millions | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | ||||||||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011
MGP And Other Sites | Sep. 30, 2010
MGP And Other Sites | Sep. 30, 2011
MGP And Other Sites | Sep. 30, 2010
MGP And Other Sites | Sep. 30, 2011
Remediation Of Distribution And Substation Transformers | Sep. 30, 2010
Remediation Of Distribution And Substation Transformers | Sep. 30, 2011
Remediation Of Distribution And Substation Transformers | Sep. 30, 2010
Remediation Of Distribution And Substation Transformers | Sep. 30, 2011
PEC | Dec. 31, 2010
PEC | Sep. 30, 2011
PEF
Nitrogen Oxides | |
Disclosure Environmental Matters Details [Line Items] | |||||||||||||
Beginning Balance | $ 35 | $ 42 | $ 20 | $ 22 | $ 15 | $ 20 | |||||||
Amount accrued for environmental loss contingencies | 7 | 18 | 0 | 0 | 1 | 7 | 0 | 0 | 6 | 11 | |||
Expenditures for environmental loss contingencies | (17) | (22) | 0 | 0 | (4) | (8) | 0 | (5) | (13) | (14) | |||
Ending Balance | 25 | 38 | 17 | 21 | 17 | 21 | 8 | 17 | 8 | 17 | |||
(Ward) site recorded liability | 5 | 5 | |||||||||||
Site contingency, loss exposure not accrued | 6 | ||||||||||||
Site contingency, loss exposure not accrued, reimbursement | 1 | ||||||||||||
Emission Allowances Inventory [Line Items] | |||||||||||||
Reduction in value of emission allowances inventory | (23) | ||||||||||||
Regulatory asset recorded for reduction in value of emission allowances inventory | $ 22 |
Organization and Summary of Significant Accounting Policies | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Organization Consolidation And Presentation Of Financial Statements Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization and Summary of Significant Accounting Policies | 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ORGANIZATION In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy's financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to Applicable Combined Notes to Unaudited Condensed Interim Financial Statements by Registrant. 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. PROGRESS ENERGY The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC). Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 13 for further information about our segments. PEC PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC's subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC. PEF PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC. B. BASIS OF PRESENTATION These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2010 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2010 (2010 Form 10-K). The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods. In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. Certain amounts for 2010 have been reclassified to conform to the 2011 presentation. The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the Statements of Income were as follows:
C. CONSOLIDATION OF VARIABLE INTEREST ENTITIES We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE's variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity. PROGRESS ENERGY Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary during 2010 or for the nine months ended September 30, 2011. No financial or other support has been provided to the VIE during the periods presented. The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:
The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses. Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million and $2 million for each of the three and nine months ended September 30, 2011 and 2010, respectively. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time. PEC See discussion of PEC's variable interests within the Progress Energy section. PEF PEF has no significant variable interests in VIEs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Organization and Summary of Significant Accounting Policies | 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ORGANIZATION In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy's financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to Applicable Combined Notes to Unaudited Condensed Interim Financial Statements by Registrant. 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. PROGRESS ENERGY The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC). Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 13 for further information about our segments. PEC PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC's subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC. PEF PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC. B. BASIS OF PRESENTATION These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2010 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2010 (2010 Form 10-K). The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods. In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. Certain amounts for 2010 have been reclassified to conform to the 2011 presentation. The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the Statements of Income were as follows:
C. CONSOLIDATION OF VARIABLE INTEREST ENTITIES We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE's variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity. PROGRESS ENERGY Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary during 2010 or for the nine months ended September 30, 2011. No financial or other support has been provided to the VIE during the periods presented. The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:
The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses. Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million and $2 million for each of the three and nine months ended September 30, 2011 and 2010, respectively. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time. PEC See discussion of PEC's variable interests within the Progress Energy section. PEF PEF has no significant variable interests in VIEs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Organization and Summary of Significant Accounting Policies | 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ORGANIZATION In this report, Progress Energy, which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis, is at times referred to as “we,” “us” or “our.” When discussing Progress Energy's financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to Applicable Combined Notes to Unaudited Condensed Interim Financial Statements by Registrant. 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. PROGRESS ENERGY The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC). Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 13 for further information about our segments. PEC PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC's subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC. PEF PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC. B. BASIS OF PRESENTATION These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The December 31, 2010 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2010 (2010 Form 10-K). The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods. In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. Certain amounts for 2010 have been reclassified to conform to the 2011 presentation. The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the Statements of Income were as follows:
C. CONSOLIDATION OF VARIABLE INTEREST ENTITIES We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE's variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity. PROGRESS ENERGY Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary during 2010 or for the nine months ended September 30, 2011. No financial or other support has been provided to the VIE during the periods presented. The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:
The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses. Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million and $2 million for each of the three and nine months ended September 30, 2011 and 2010, respectively. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time. PEC See discussion of PEC's variable interests within the Progress Energy section. PEF PEF has no significant variable interests in VIEs. |
Regulatory Matters | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Regulatory Matters | 4. REGULATORY MATTERS On January 8, 2011, Progress Energy and Duke Energy entered into the Merger Agreement. See Note 2 for regulatory information related to the Merger with Duke Energy. A. PEC RETAIL RATE MATTERS COST RECOVERY FILINGS On June 3, 2011, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina retail ratepayers, driven by rising fuel prices. On September 15, 2011, PEC filed a settlement agreement for an increase of approximately $85 million in the fuel rate. The settlement agreement updated certain costs from PEC's original filing and included the impact of a $24 million disallowance of replacement power costs resulting from prior-year performance of PEC's nuclear plants. If approved, the increase will be effective December 1, 2011, and will increase residential electric bills by $2.75 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. On June 3, 2011, and as subsequently amended on August 23, 2011, PEC also filed for a $24 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate charged to its North Carolina ratepayers which, if approved, will be effective December 1, 2011, and will increase the residential electric bills by $1.08 per 1,000 kWh for DSM and EE cost recovery. On June 3, 2011, and as subsequently amended on September 8, 2011, PEC also requested a $9 million increase for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), which if approved, will be effective December 1, 2011, and will decrease the residential electric bills by $0.02 per 1,000 kWh. The residential NC REPS rate decreased while the total amount to be recovered increased due to the allocation of the NC REPS recovery between customer classes. The net impact of the settlement agreement and filings results in an average increase in residential electric bills of 3.7 percent. We cannot predict the outcome of these matters. On June 29, 2011, the SCPSC approved a $22 million increase in the fuel rate charged to PEC's South Carolina ratepayers, driven by rising fuel prices. The increase was effective July 1, 2011, and increased residential electric bills by $3.45 per 1,000 kWh. Also on June 20, 2011, the SCPSC provisionally approved a $4 million increase in the DSM and EE rate. The increase was effective July 1, 2011, and increased residential electric bills by $1.25 per 1,000 kWh. The net impact of the two filings resulted in an average increase in residential electric bills of 4.7 percent. We cannot predict the outcome of this matter. OTHER MATTERS Construction of Generating Facilities The NCUC has granted PEC permission to construct two new generating facilities: an approximately 950-MW combined cycle natural gas-fueled facility at its Lee generation facility and an approximately 620-MW natural gas-fueled facility at its Sutton generation facility. The facilities are expected to be placed in service in January 2013 and December 2013, respectively. Planned Retirements of Generating Facilities PEC filed a plan with the NCUC and the SCPSC to retire all of its coal-fired generating facilities in North Carolina that do not have scrubbers. These facilities total approximately 1,500 MW at four sites. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units. PEC expects to retire the remaining coal-fired facilities by the end of 2013. The net carrying value of the four facilities at September 30, 2011, of $171 million is included in other utility plant, net on the Consolidated Balance Sheets. Consistent with ratemaking treatment, PEC will continue to depreciate each plant using the current depreciation lives and rates on file with the NCUC and the SCPSC until the earlier of the plant's retirement or PEC's completion and filing of a new depreciation study on or before March 31, 2013. The final recovery periods may change in connection with the regulators' determination of the recovery of the remaining net carrying value. B. PEF RETAIL RATE MATTERS CR3 OUTAGE In September 2009, PEF's Crystal River Unit No. 3 Nuclear Plant (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit's steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes in the partially tensioned containment building and additional cracking or delaminations may have occurred or could occur during the repair process. PEF analyzed multiple repair options as well as early decommissioning and believes, based on the information and analyses conducted to date, that repairing the unit is the best option. PEF engaged outside engineering consultants to perform the analysis of possible repair options for the second delamination. The consultants analyzed 22 potential repair options and ultimately narrowed those to four. PEF, along with other independent consultants, reviewed the four options for technical issues, constructability, and licensing feasibility as well as cost. Based on that initial analysis, PEF selected the best repair option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the final repair is underway. PEF will update the current estimate as this work is completed. PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any final repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments. CR3's current operating license expires in December 2016, and PEF applied for a 20-year renewal of the license in 2008. PEF understands that the NRC has completed the license extension process with the exception of the containment structure repair. Once the repair design has been completed and evaluated, the NRC can proceed with the review of the containment structure. Assuming the repair is successful, management is not aware of any reasons why CR3 will not satisfy the requirements for the license extension. PEF maintains insurance for property damage and incremental costs of replacement power resulting from prolonged accidental outages through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accident but has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through September 30, 2011. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. As discussed below, PEF considers replacement power costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause. PEF also maintains insurance coverage through NEIL's accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. The following table summarizes the CR3 replacement power and repair costs and recovery through September 30, 2011:
PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. PEF has recorded $324 million of NEIL replacement power cost reimbursements subsequent to the deductible period, of which $162 million has been received to date. PEF has received $45 million of replacement power reimbursements from NEIL for the nine months ended September 30, 2011. No replacement power reimbursements have been received from NEIL for the three months ended September 30, 2011. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. We cannot predict with certainty the future recoverability of these costs. Failure to recover some or all of these costs could have a material adverse effect on our and PEF's financial results. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed. On October 25, 2010, the FPSC approved PEF's motion to establish a separate spin-off docket to review the prudence and costs related to the outage and replacement fuel and power costs associated with the CR3 extended outage. This docket will allow the FPSC to evaluate PEF's actions concerning the concrete delamination and review PEF's resulting costs associated with the extended outage. On June 27, 2011, PEF filed an updated status report with the NRC and FPSC regarding the CR3 outage. The FPSC held subsequent status conferences regarding the CR3 outage on July 14, 2011, and August 8, 2011. On August 23, 2011, the FPSC issued an order dividing the docket into three phases. The first phase will include a prudence review of the events and decisions of PEF leading up to the October 2, 2009 delamination event. A hearing has been scheduled for June 11-15, 2012. The second phase will be a consideration of the prudence of PEF's decision to repair rather than decommission CR3. The third phase of this docket will include the decisions and events subsequent to the October 2, 2009 delamination leading up to the March 14, 2011 delamination event and the subsequent repair of the containment building. The hearing dates and schedules for the second and third phases will be set in subsequent orders. PEF will file status reports regarding its analysis of the engineering reports, costs, schedule for completion of the repair, along with updated information regarding the decision to repair rather than decommission CR3, and updates regarding the repair of the containment building in accordance with the controlling dates set forth by the FPSC. The first status report is due January 9, 2012. We cannot predict the outcome of these matters. COST OF REMOVAL RESERVE The base rate settlement agreement in effect through the last billing cycle of 2012 provides PEF the discretion to reduce amortization expense (cost of removal component) by up to $150 million in 2010, up to $250 million in 2011, and up to any remaining balance in the cost of removal reserve in 2012 until the earlier of (a) PEF's applicable cost of removal reserve reaches zero, or (b) the expiration of the settlement agreement at the end of 2012. In the event PEF reduces amortization expense by less than the annual amounts for 2010 or 2011, PEF may carry forward (i.e., increase the annual cap by) any unused cost of removal reserve amounts in subsequent years during the term of the agreement. Pursuant to the settlement agreement, PEF carried an unused balance of $90 million forward from 2010, which is available to reduce future amortization expense. For the nine months ended September 30, 2011, PEF recognized a $205 million reduction in amortization expense. Under the base rate settlement agreement, PEF had eligible cost of removal reserves of $294 million remaining as of September 30, 2011. The balance of the cost of removal reserve is impacted by accruals in accordance with PEF's latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreement. FUEL COST RECOVERY On September 1, 2011, and as subsequently adjusted by the FPSC (see “Nuclear Cost Recovery”), PEF filed its annual fuel-cost recovery filing, requesting to increase the total fuel-cost recovery by $162 million, increasing the residential rate by $3.32 per 1,000 kWh, or 2.78 percent, which will be effective January 1, 2012 if approved. This increase is due to an increase of $3.99 per 1,000 kWh for the projected recovery of fuel costs offset by a decrease of $0.67 per 1,000 kWh for the projected recovery through the Capacity Cost-Recovery Clause (CCRC). The increase in the projected recovery of fuel costs is due to an under-recovery from the prior year. The decrease in the CCRC is primarily due to lower anticipated costs associated with PEF's proposed Levy Units No. 1 and No. 2 Nuclear Power Plants (Levy), and the deferral of 2011 and 2012 estimated costs associated with PEF's CR3 uprate project until 2012 (see “Nuclear Cost Recovery”), partially offset by increased capacity costs and a reduction of the refund related to an over-recovery from the prior year. A hearing was held on November 1-2, 2011. An agenda conference has been scheduled for November 22, 2011. We cannot predict the outcome of this matter. NUCLEAR COST RECOVERY Levy Nuclear Major construction activities on Levy have been postponed until after the NRC issues the combined license (COL) for the plants, which is expected in 2013 if the current licensing schedule remains on track. Along with the FPSC's annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF's preferred baseload generation option. CR3 Uprate In 2007, the FPSC issued an order approving PEF's Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3's gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011. Cost Recovery On October 24, 2011, the FPSC approved a $78 million decrease in the amount charged to PEF's ratepayers for nuclear cost recovery, which is a component of, and is included in, the fuel cost recovery (See “Fuel Cost Recovery”), including recovery of pre-construction and carrying costs and CCRC recoverable O&M expense anticipated to be incurred during 2012, recovery of $60 million of prior years' deferrals in 2012, as well as the estimated actual true-up of 2011 costs associated with the Levy and CR3 uprate projects. Also included is the stipulation of PEF's filed motion with the FPSC to defer until 2012 the approval of the long-term feasibility analysis of completing the CR3 uprate, and the determination of reasonableness on, and recovery of, 2011 and 2012 estimated costs. This results in an estimated decrease in the nuclear cost-recovery charge of $2.67 per 1,000 kWh for residential customers, beginning with the first January 2012 billing cycle. The approved rate did not include PEF's request to apply the 2011 over-recovery against the prior-years' deferrals, but rather provides for the refund of $55 million for those prior period over collections. Under the FPSC's ruling, the prior-years' deferral will be recovered consistent with the 2009 rate mitigation plan as approved by the FPSC in 2009, which presented the recovery of costs over a five-year period. DEMAND-SIDE MANAGEMENT On July 26, 2011, the FPSC voted to set PEF's DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener timely filed a protest to the FPSC's Proposed Agency Action order, asserting legal challenges to the order. The FPSC has approved a briefing schedule for the parties to make legal arguments to the FPSC. We cannot predict the outcome of this matter. On November 1, 2011, the FPSC approved PEF's request to decrease the Energy Conservation Cost Recovery Clause (ECCR) residential rate by $0.11 per 1,000 kWh, or 0.1 percent of the total residential rate, effective January 1, 2012. The decrease in the ECCR is primarily due to an increased refund of a prior period over-recovery, partially offset by an increase in conservation program costs. OTHER MATTERS On August 26, 2011, and as subsequently revised on October 14, 2011, PEF filed its annual Environmental Cost Recovery Clause (ECRC) filing, requesting to increase the ECRC by $24 million, increasing the residential rate by $0.54 per 1,000 kWh, or 0.5 percent, which would be effective January 1, 2012 if approved. The increase in the ECRC is primarily due to the 2011 return of a prior period over-recovery, partially offset by a decrease in the related O&M expense. A hearing was held on November 1-2, 2011. A subsequent agenda conference has been scheduled for November 22, 2011. We cannot predict the outcome of this matter. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Regulatory Matters Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters | A. PEC RETAIL RATE MATTERS COST RECOVERY FILINGS On June 3, 2011, PEC filed with the NCUC for an increase in the fuel rate charged to its North Carolina retail ratepayers, driven by rising fuel prices. On September 15, 2011, PEC filed a settlement agreement for an increase of approximately $85 million in the fuel rate. The settlement agreement updated certain costs from PEC's original filing and included the impact of a $24 million disallowance of replacement power costs resulting from prior-year performance of PEC's nuclear plants. If approved, the increase will be effective December 1, 2011, and will increase residential electric bills by $2.75 per 1,000 kilowatt-hours (kWh) for fuel cost recovery. On June 3, 2011, and as subsequently amended on August 23, 2011, PEC also filed for a $24 million increase in the demand-side management (DSM) and energy-efficiency (EE) rate charged to its North Carolina ratepayers which, if approved, will be effective December 1, 2011, and will increase the residential electric bills by $1.08 per 1,000 kWh for DSM and EE cost recovery. On June 3, 2011, and as subsequently amended on September 8, 2011, PEC also requested a $9 million increase for North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS), which if approved, will be effective December 1, 2011, and will decrease the residential electric bills by $0.02 per 1,000 kWh. The residential NC REPS rate decreased while the total amount to be recovered increased due to the allocation of the NC REPS recovery between customer classes. The net impact of the settlement agreement and filings results in an average increase in residential electric bills of 3.7 percent. We cannot predict the outcome of these matters. On June 29, 2011, the SCPSC approved a $22 million increase in the fuel rate charged to PEC's South Carolina ratepayers, driven by rising fuel prices. The increase was effective July 1, 2011, and increased residential electric bills by $3.45 per 1,000 kWh. Also on June 20, 2011, the SCPSC provisionally approved a $4 million increase in the DSM and EE rate. The increase was effective July 1, 2011, and increased residential electric bills by $1.25 per 1,000 kWh. The net impact of the two filings resulted in an average increase in residential electric bills of 4.7 percent. We cannot predict the outcome of this matter. OTHER MATTERS Construction of Generating Facilities The NCUC has granted PEC permission to construct two new generating facilities: an approximately 950-MW combined cycle natural gas-fueled facility at its Lee generation facility and an approximately 620-MW natural gas-fueled facility at its Sutton generation facility. The facilities are expected to be placed in service in January 2013 and December 2013, respectively. Planned Retirements of Generating Facilities PEC filed a plan with the NCUC and the SCPSC to retire all of its coal-fired generating facilities in North Carolina that do not have scrubbers. These facilities total approximately 1,500 MW at four sites. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units. PEC expects to retire the remaining coal-fired facilities by the end of 2013. The net carrying value of the four facilities at September 30, 2011, of $171 million is included in other utility plant, net on the Consolidated Balance Sheets. Consistent with ratemaking treatment, PEC will continue to depreciate each plant using the current depreciation lives and rates on file with the NCUC and the SCPSC until the earlier of the plant's retirement or PEC's completion and filing of a new depreciation study on or before March 31, 2013. The final recovery periods may change in connection with the regulators' determination of the recovery of the remaining net carrying value. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PEF | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters | B. PEF RETAIL RATE MATTERS CR3 OUTAGE In September 2009, PEF's Crystal River Unit No. 3 Nuclear Plant (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit's steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes in the partially tensioned containment building and additional cracking or delaminations may have occurred or could occur during the repair process. PEF analyzed multiple repair options as well as early decommissioning and believes, based on the information and analyses conducted to date, that repairing the unit is the best option. PEF engaged outside engineering consultants to perform the analysis of possible repair options for the second delamination. The consultants analyzed 22 potential repair options and ultimately narrowed those to four. PEF, along with other independent consultants, reviewed the four options for technical issues, constructability, and licensing feasibility as well as cost. Based on that initial analysis, PEF selected the best repair option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the final repair is underway. PEF will update the current estimate as this work is completed. PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any final repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments. CR3's current operating license expires in December 2016, and PEF applied for a 20-year renewal of the license in 2008. PEF understands that the NRC has completed the license extension process with the exception of the containment structure repair. Once the repair design has been completed and evaluated, the NRC can proceed with the review of the containment structure. Assuming the repair is successful, management is not aware of any reasons why CR3 will not satisfy the requirements for the license extension. PEF maintains insurance for property damage and incremental costs of replacement power resulting from prolonged accidental outages through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accident but has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. An additional 71 weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through September 30, 2011. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. As discussed below, PEF considers replacement power costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause. PEF also maintains insurance coverage through NEIL's accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim. PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. The following table summarizes the CR3 replacement power and repair costs and recovery through September 30, 2011:
PEF believes the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. PEF has recorded $324 million of NEIL replacement power cost reimbursements subsequent to the deductible period, of which $162 million has been received to date. PEF has received $45 million of replacement power reimbursements from NEIL for the nine months ended September 30, 2011. No replacement power reimbursements have been received from NEIL for the three months ended September 30, 2011. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. We cannot predict with certainty the future recoverability of these costs. Failure to recover some or all of these costs could have a material adverse effect on our and PEF's financial results. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed. On October 25, 2010, the FPSC approved PEF's motion to establish a separate spin-off docket to review the prudence and costs related to the outage and replacement fuel and power costs associated with the CR3 extended outage. This docket will allow the FPSC to evaluate PEF's actions concerning the concrete delamination and review PEF's resulting costs associated with the extended outage. On June 27, 2011, PEF filed an updated status report with the NRC and FPSC regarding the CR3 outage. The FPSC held subsequent status conferences regarding the CR3 outage on July 14, 2011, and August 8, 2011. On August 23, 2011, the FPSC issued an order dividing the docket into three phases. The first phase will include a prudence review of the events and decisions of PEF leading up to the October 2, 2009 delamination event. A hearing has been scheduled for June 11-15, 2012. The second phase will be a consideration of the prudence of PEF's decision to repair rather than decommission CR3. The third phase of this docket will include the decisions and events subsequent to the October 2, 2009 delamination leading up to the March 14, 2011 delamination event and the subsequent repair of the containment building. The hearing dates and schedules for the second and third phases will be set in subsequent orders. PEF will file status reports regarding its analysis of the engineering reports, costs, schedule for completion of the repair, along with updated information regarding the decision to repair rather than decommission CR3, and updates regarding the repair of the containment building in accordance with the controlling dates set forth by the FPSC. The first status report is due January 9, 2012. We cannot predict the outcome of these matters. COST OF REMOVAL RESERVE The base rate settlement agreement in effect through the last billing cycle of 2012 provides PEF the discretion to reduce amortization expense (cost of removal component) by up to $150 million in 2010, up to $250 million in 2011, and up to any remaining balance in the cost of removal reserve in 2012 until the earlier of (a) PEF's applicable cost of removal reserve reaches zero, or (b) the expiration of the settlement agreement at the end of 2012. In the event PEF reduces amortization expense by less than the annual amounts for 2010 or 2011, PEF may carry forward (i.e., increase the annual cap by) any unused cost of removal reserve amounts in subsequent years during the term of the agreement. Pursuant to the settlement agreement, PEF carried an unused balance of $90 million forward from 2010, which is available to reduce future amortization expense. For the nine months ended September 30, 2011, PEF recognized a $205 million reduction in amortization expense. Under the base rate settlement agreement, PEF had eligible cost of removal reserves of $294 million remaining as of September 30, 2011. The balance of the cost of removal reserve is impacted by accruals in accordance with PEF's latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreement. FUEL COST RECOVERY On September 1, 2011, and as subsequently adjusted by the FPSC (see “Nuclear Cost Recovery”), PEF filed its annual fuel-cost recovery filing, requesting to increase the total fuel-cost recovery by $162 million, increasing the residential rate by $3.32 per 1,000 kWh, or 2.78 percent, which will be effective January 1, 2012 if approved. This increase is due to an increase of $3.99 per 1,000 kWh for the projected recovery of fuel costs offset by a decrease of $0.67 per 1,000 kWh for the projected recovery through the Capacity Cost-Recovery Clause (CCRC). The increase in the projected recovery of fuel costs is due to an under-recovery from the prior year. The decrease in the CCRC is primarily due to lower anticipated costs associated with PEF's proposed Levy Units No. 1 and No. 2 Nuclear Power Plants (Levy), and the deferral of 2011 and 2012 estimated costs associated with PEF's CR3 uprate project until 2012 (see “Nuclear Cost Recovery”), partially offset by increased capacity costs and a reduction of the refund related to an over-recovery from the prior year. A hearing was held on November 1-2, 2011. An agenda conference has been scheduled for November 22, 2011. We cannot predict the outcome of this matter. NUCLEAR COST RECOVERY Levy Nuclear Major construction activities on Levy have been postponed until after the NRC issues the combined license (COL) for the plants, which is expected in 2013 if the current licensing schedule remains on track. Along with the FPSC's annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF's preferred baseload generation option. CR3 Uprate In 2007, the FPSC issued an order approving PEF's Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3's gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011. Cost Recovery On October 24, 2011, the FPSC approved a $78 million decrease in the amount charged to PEF's ratepayers for nuclear cost recovery, which is a component of, and is included in, the fuel cost recovery (See “Fuel Cost Recovery”), including recovery of pre-construction and carrying costs and CCRC recoverable O&M expense anticipated to be incurred during 2012, recovery of $60 million of prior years' deferrals in 2012, as well as the estimated actual true-up of 2011 costs associated with the Levy and CR3 uprate projects. Also included is the stipulation of PEF's filed motion with the FPSC to defer until 2012 the approval of the long-term feasibility analysis of completing the CR3 uprate, and the determination of reasonableness on, and recovery of, 2011 and 2012 estimated costs. This results in an estimated decrease in the nuclear cost-recovery charge of $2.67 per 1,000 kWh for residential customers, beginning with the first January 2012 billing cycle. The approved rate did not include PEF's request to apply the 2011 over-recovery against the prior-years' deferrals, but rather provides for the refund of $55 million for those prior period over collections. Under the FPSC's ruling, the prior-years' deferral will be recovered consistent with the 2009 rate mitigation plan as approved by the FPSC in 2009, which presented the recovery of costs over a five-year period. DEMAND-SIDE MANAGEMENT On July 26, 2011, the FPSC voted to set PEF's DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener timely filed a protest to the FPSC's Proposed Agency Action order, asserting legal challenges to the order. The FPSC has approved a briefing schedule for the parties to make legal arguments to the FPSC. We cannot predict the outcome of this matter. On November 1, 2011, the FPSC approved PEF's request to decrease the Energy Conservation Cost Recovery Clause (ECCR) residential rate by $0.11 per 1,000 kWh, or 0.1 percent of the total residential rate, effective January 1, 2012. The decrease in the ECCR is primarily due to an increased refund of a prior period over-recovery, partially offset by an increase in conservation program costs. OTHER MATTERS On August 26, 2011, and as subsequently revised on October 14, 2011, PEF filed its annual Environmental Cost Recovery Clause (ECRC) filing, requesting to increase the ECRC by $24 million, increasing the residential rate by $0.54 per 1,000 kWh, or 0.5 percent, which would be effective January 1, 2012 if approved. The increase in the ECRC is primarily due to the 2011 return of a prior period over-recovery, partially offset by a decrease in the related O&M expense. A hearing was held on November 1-2, 2011. A subsequent agenda conference has been scheduled for November 22, 2011. We cannot predict the outcome of this matter. |
Debt and Credit Facilities - Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified | 3 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | ||||||||
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Sep. 30, 2011 | Dec. 31, 2010 | Jun. 30, 2011
Parent | Dec. 31, 2010
Parent | Mar. 31, 2011
Senior Notes
Parent | Sep. 30, 2011
PEC | Dec. 31, 2010
PEC | Sep. 30, 2011
PEC
First Mortgage Bonds Due September 15, 2021 | Sep. 30, 2011
PEF | Dec. 31, 2010
PEF | Jun. 30, 2011
PEF
First Mortgage Bonds Due July 15, 2011 | Sep. 30, 2011
PEF
First Mortgage Bonds Due August 15, 2021 | Mar. 31, 2011
Senior Notes Due March 1, 2011 | Jun. 30, 2011
Original Expiration | |
Long-term debt [Line Items] | ||||||||||||||
Debt instrument, face amount | $ 500 | $ 500 | $ 300 | |||||||||||
Maturity date | Jan. 15, 2021 | Sep. 15, 2021 | Jul. 15, 2011 | Aug. 15, 2021 | Mar. 01, 2011 | |||||||||
Current portion of long-term debt | (950) | (505) | (500) | 0 | 0 | (300) | ||||||||
Long-term debt, net | 11,717 | 11,864 | 3,693 | 3,693 | 4,482 | 4,182 | ||||||||
Long-term debt, affiliate | 273 | 273 | ||||||||||||
Maturities of debt | 300 | 700 | ||||||||||||
Debt instrument issuance date | January 21, 2011 | September 15, 2011 | August 18, 2011 | |||||||||||
Debt instrument, interest rate stated percentage | 4.40% | 3.00% | 6.65% | 3.10% | 7.10% | |||||||||
RCAs and available capacity [Line Items] | ||||||||||||||
RCA expiration date | May 3, 2011 | |||||||||||||
RCA total | 478 | 500 | 22 | |||||||||||
RCA available | 1,978 | |||||||||||||
Short Term Debt [Line Items] | ||||||||||||||
Short-term debt | $ 45 | $ 0 |
Organization and Summary of Significant Accounting Policies (Details) (USD $) In Millions | 3 Months Ended | 9 Months Ended | ||||
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Sep. 30, 2011 | Sep. 30, 2010 | Sep. 30, 2011 | Sep. 30, 2010 | Dec. 31, 2010 | Dec. 31, 2009 | |
Excise taxes | ||||||
Excise taxes | $ 96 | $ 101 | $ 245 | $ 265 | ||
Consolidation of variable interest entities | ||||||
Cumulative effect of change in accounting principle | 10,115 | 10,024 | 10,115 | 10,024 | 10,027 | 9,455 |
Miscellaneous other property and investments | 12 | 12 | 12 | |||
Cash and cash equivalents | 1 | 1 | 0 | |||
Prepayments and other current assets | 0 | 0 | 1 | |||
Accounts payable | 0 | 0 | 5 | |||
VIE - exposure to loss from capital lease agreements | 7.5 | 7.5 | ||||
VIE - activity with VIE related to lease payments | $ 1 | $ 1 | $ 2 | $ 2 |
Subsequent Events (Details) | Sep. 30, 2011 |
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Subsequent Events Merger Agreement [Abstract] | |
Merger Share Exchange Ratio | 2.6125 |
Other Income and Other Expense (Details) (USD $) In Millions | 3 Months Ended | 9 Months Ended |
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Sep. 30, 2011 | Sep. 30, 2011 | |
Disclosure Other Income And Other Expense Details [Abstract] | ||
CVOs unrealized gain, net | $ (50) | $ (46) |
Equity | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Equity And Comprehensive Income Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity | 5. EQUITY AND COMPREHENSIVE INCOME A. EARNINGS PER COMMON SHARE There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2011 and 2010. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial. B. RECONCILIATION OF TOTAL EQUITY PROGRESS ENERGY The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders' proportionate share of the equity of a subsidiary and a VIE (See Note 1C). The following table presents changes in total equity for the year to date:
PEC Interim disclosures of changes in equity are required if the reporting entity has less than wholly owned subsidiaries, of which PEC has none. Therefore, an equity reconciliation for PEC has not been provided. PEF Interim disclosures of changes in equity are required if the reporting entity has less than wholly owned subsidiaries, of which PEF has none. Therefore, an equity reconciliation for PEF has not been provided. C. COMPREHENSIVE INCOME
D. COMMON STOCK At September 30, 2011 and December 31, 2010, we had 500 million shares of common stock authorized under our charter, of which 295 million and 293 million shares were outstanding, respectively. We periodically issue shares of common stock through the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)), the Progress Energy Investor Plus Plan (IPP) and other benefit plans. The following table presents information for our common stock issuances:
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PEC | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity And Comprehensive Income Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity | 5. EQUITY AND COMPREHENSIVE INCOME A. EARNINGS PER COMMON SHARE There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2011 and 2010. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial. B. RECONCILIATION OF TOTAL EQUITY PEC Interim disclosures of changes in equity are required if the reporting entity has less than wholly owned subsidiaries, of which PEC has none. Therefore, an equity reconciliation for PEC has not been provided. C. COMPREHENSIVE INCOME
D. COMMON STOCK At September 30, 2011 and December 31, 2010, we had 500 million shares of common stock authorized under our charter, of which 295 million and 293 million shares were outstanding, respectively. We periodically issue shares of common stock through the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)), the Progress Energy Investor Plus Plan (IPP) and other benefit plans. The following table presents information for our common stock issuances:
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PEF | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity And Comprehensive Income Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity | 5. EQUITY AND COMPREHENSIVE INCOME A. EARNINGS PER COMMON SHARE There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2011 and 2010. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial. B. RECONCILIATION OF TOTAL EQUITY PEF Interim disclosures of changes in equity are required if the reporting entity has less than wholly owned subsidiaries, of which PEF has none. Therefore, an equity reconciliation for PEF has not been provided. C. COMPREHENSIVE INCOME
D. COMMON STOCK At September 30, 2011 and December 31, 2010, we had 500 million shares of common stock authorized under our charter, of which 295 million and 293 million shares were outstanding, respectively. We periodically issue shares of common stock through the Progress Energy 401(k) Savings & Stock Ownership Plan (401(k)), the Progress Energy Investor Plus Plan (IPP) and other benefit plans. The following table presents information for our common stock issuances:
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Risk Management Activities and Derivative Transactions (Tables) | 3 Months Ended | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2011 | Sep. 30, 2011 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management Activities And Derivative Transactions Tables [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of derivative instruments |
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Effect of derivative instruments on other comprehensive income - derivatives designated as hedging instruments |
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Effect of derivative instruments on regulatory assets and liabilities - derivatives not designated as hedging instruments |
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Effect of derivative instruments on income - derivatives not designated as hedging instruments |
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