Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
-------- --------
Exact name of registrants as specified in their charters, state of I.R.S. Employer
Commission incorporation, address of principal executive offices, and telephone Identification
File Number number Number
1-15929 Progress Energy, Inc. 56-2155481
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
1-3382 Carolina Power & Light Company 56-0165465
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
NONE
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark whether Progress Energy, Inc. (Progress Energy) is an
accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No
Indicate by check mark whether Carolina Power & Light Company is an accelerated
filer (as defined in Rule 12b-2 of the Exchange Act). Yes No X
This combined Form 10-Q is filed separately by two registrants: Progress Energy
and Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC).
Information contained herein relating to either individual registrant is filed
by such registrant solely on its own behalf. Each registrant makes no
representation as to information relating exclusively to the other registrant.
Indicate the number of shares outstanding of each of the issuers' classes of
common stock, as of the latest practicable date. As of April 30, 2005, each
registrant had the following shares of common stock outstanding:
Registrant Description Shares
Progress Energy Common Stock (Without Par Value) 248,680,504
PEC Common Stock (Without Par Value) 159,608,055 (all of which
were held by Progress Energy, Inc.)
1
PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC.
FORM 10-Q - For the Quarter Ended March 31, 2005
Glossary of Terms
Safe Harbor For Forward-Looking Statements
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Interim Financial Statements:
Progress Energy, Inc.
--------------------------------------------------------------
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
---------------------------------------------------------------
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
Signatures
2
GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined Form
10-Q are defined below:
TERM DEFINITION
401(k) Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement related to retail rate matters
ARO Asset retirement obligation
Bcf Billion cubic feet
Btu British thermal unit
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
CCO Competitive Commercial Operations business segment
CERCLA or Superfund Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended
Code Internal Revenue Code
Colona Colona Synfuel Limited Partnership, LLLP
the Company Progress Energy, Inc. and subsidiaries
CP&L Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc.
CR3 Crystal River Unit No. 3
CVO Contingent value obligation
DOE United States Department of Energy
DWM North Carolina Department of Environment and Natural Resources, Division of
Waste Management
ECRC Environmental Cost Recovery Clause
EITF Emerging Issues Task Force
EMCs Electric Membership Cooperatives
EPA of 1992 Energy Policy Act of 1992
FASB Financial Accounting Standards Board
FDEP Florida Department of Environment and Protection
FERC Federal Energy Regulatory Commission
FIN No. 45 Financial Accounting Standards Board (FASB) Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
FIN No. 46R FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities -
an Interpretation of ARB No. 51"
Florida Progress or FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Fuels Fuels business segment
GAAP Accounting Principles Generally Accepted in the United States of America
Global U.S. Global LLC
the holding company Progress Energy Corporate
IRS Internal Revenue Service
Jackson Jackson Electric Membership Corporation
LIBOR London Inter Bank Offering Rate
MACT Maximum Achievable Control Technology
Medicare Act Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP Manufactured Gas Plant
MW Megawatt
MWh Megawatt-hour
NCUC North Carolina Utilities Commission
NOx Nitrogen Oxide
NOx SIP Call EPA rule which requires 22 states including North and South Carolina to
further reduce nitrogen oxide emissions.
NRC United States Nuclear Regulatory Commission
Nuclear Waste Act Nuclear Waste Policy Act of 1982
3
O&M Operations & Maintenance Expense
OPEB Postretirement benefits other than pensions
PEC Progress Energy Carolinas, Inc., formerly referred to as Carolina Power &
Light Company
PEC Electric PEC Electric business segment made up of the utility operations and
excludes operations of nonregulated subsidiaries
PEF Progress Energy Florida, formerly referred to as Florida Power Corporation
PFA IRS Prefiling Agreement
PLR Private Letter Ruling
Progress Energy Progress Energy, Inc.
Progress Fuels Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail Progress Rail Services Corporation
Progress Ventures Business unit of Progress Energy primarily made up of nonregulated energy
generation and marketing activities, as well as gas, coal and synthetic
fuel operations
PRP Potentially responsible party, as defined in CERCLA
PTC Progress Telecommunications Corporation
PT LLC Progress Telecom, LLC
PUHCA Public Utility Holding Company Act of 1935, as amended
PVI Progress Energy Ventures, Inc. (formerly referred to as CPL Energy
Ventures, Inc.)
Rail Services Rail Services business segment
RCA Revolving credit agreement
ROE Return on Equity
SCPSC Public Service Commission of South Carolina
SEC United States Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Service Code
Service Company Progress Energy Service Company, LLC
SFAS Statement of Financial Accounting Standards
SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for
Contingencies"
SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation"
SFAS No. 123R Statement of Financial Accounting Standards No. 123R, "Accounting for
Stock-Based Compensation"
SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative and Hedging Activities"
SFAS No. 138 Statement of Financial Accounting Standards No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities - An
Amendment of FASB Statement No. 133"
SFAS No. 143 Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations"
SFAS No. 148 Statement of Financial Accounting Standards No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB
Statement No. 123"
Smokestacks Act North Carolina Clean Smokestacks Act enacted in June 2002
SO2 Sulfur dioxide
SRS Strategic Resource Solutions Corp.
the Trust FPC Capital I
4
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This combined report contains forward-looking statements within the meaning of
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995. The matters discussed throughout this combined Form 10-Q that are not
historical facts are forward-looking and, accordingly, involve estimates,
projections, goals, forecasts, assumptions, risks and uncertainties that could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements.
In addition, forward-looking statements are discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
including, but not limited to, statements under the sub-heading "Results of
Operations" about trends and uncertainties, "Liquidity and Capital Resources"
about future liquidity requirements and "Other Matters" about the Company's
synthetic fuel facilities.
Any forward-looking statement is based on information current as of the date of
this report and speaks only as of the date on which such statement is made, and
neither Progress Energy, Inc. (Progress Energy or the Company) nor Progress
Energy Carolinas, Inc. (PEC) undertakes any obligation to update any
forward-looking statement or statements to reflect events or circumstances after
the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; deregulation or restructuring in
the electric industry that may result in increased competition and unrecovered
(stranded) costs; the uncertainty regarding the timing, creation and structure
of regional transmission organizations; weather conditions that directly
influence the demand for electricity; the Company's ability to recover through
the regulatory process, and the timing of such recovery of, the costs associated
with the four hurricanes that impacted our service territory in 2004 or other
future significant weather events; recurring seasonal fluctuations in demand for
electricity; fluctuations in the price of energy commodities and purchased
power; economic fluctuations and the corresponding impact on the Company and its
subsidiaries' commercial and industrial customers; the ability of the Company's
subsidiaries to pay upstream dividends or distributions to it; the impact on the
facilities and the businesses of the Company from a terrorist attack; the
inherent risks associated with the operation of nuclear facilities, including
environmental, health, regulatory and financial risks; the ability to
successfully access capital markets on favorable terms; the ability of the
Company to maintain its current credit ratings and the impact on the Company's
financial condition and ability to meet its cash and other financial obligations
in the event its credit ratings are downgraded below investment grade; the
impact that increases in leverage may have on the Company; the impact of
derivative contracts used in the normal course of business by the Company;
investment performance of pension and benefit plans; the Company's ability to
control costs, including pension and benefit expense, and achieve its cost
management targets for 2007; the availability and use of Internal Revenue Code
Section 29 (Section 29) tax credits by synthetic fuel producers and the
Company's continued ability to use Section 29 tax credits related to its coal
and synthetic fuel businesses; the impact to the Company's financial condition
and performance in the event it is determined the Company is not entitled to
previously taken Section 29 tax credits; the impact of future accounting
pronouncements regarding uncertain tax positions; the outcome of Progress Energy
Florida's (PEF) rate proceeding in 2005 regarding its future base rates; the
Company's ability to manage the risks involved with the operation of its
nonregulated plants, including dependence on third parties and related
counter-party risks, and a lack of operating history; the Company's ability to
manage the risks associated with its energy marketing operations; the outcome of
any ongoing or future litigation or similar disputes and the impact of any such
outcome or related settlements; and unanticipated changes in operating expenses
and capital expenditures. Many of these risks similarly impact the Company's
subsidiaries.
These and other risk factors are detailed from time to time in the Company's and
PEC's filings with the United States Securities and Exchange Commission (SEC).
Many, but not all, of the factors that may impact actual results are discussed
in the Risk Factors sections of Progress Energy's and PEC's annual reports on
Form 10-K for the year ended December 31, 2004, which were filed with the SEC on
March 16, 2005. All such factors are difficult to predict, contain uncertainties
that may materially affect actual results and may be beyond the control of
Progress Energy and PEC. New factors emerge from time to time, and it is not
possible for management to predict all such factors, nor can it assess the
effect of each such factor on Progress Energy and PEC.
5
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PROGRESS ENERGY, INC.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
March 31, 2005
UNAUDITED CONSOLIDATED STATEMENTS of INCOME
- ----------------------------------------------------------------------------------------
(in millions except per share data)
Three months ended March 31, 2005 2004
- ----------------------------------------------------------------------------------------
Operating revenues
Utility $ 1,783 $ 1,685
Diversified business 415 321
- ----------------------------------------------------------------------------------------
Total operating revenues 2,198 2,006
- ----------------------------------------------------------------------------------------
Operating expenses
Utility
Fuel used in electric generation 550 493
Purchased power 198 183
Operation and maintenance 406 363
Depreciation and amortization 208 202
Taxes other than on income 117 105
Diversified business
Cost of sales 395 311
Depreciation and amortization 39 41
Other 32 30
- ----------------------------------------------------------------------------------------
Total operating expenses 1,945 1,728
- ----------------------------------------------------------------------------------------
Operating income 253 278
- ----------------------------------------------------------------------------------------
Other income (expense)
Interest income 4 2
Other, net 2 (22)
- ----------------------------------------------------------------------------------------
Total other income (expense) 6 (20)
- ----------------------------------------------------------------------------------------
Interest charges
Net interest charges 166 161
Allowance for borrowed funds used during construction (3) (1)
- ----------------------------------------------------------------------------------------
Total interest charges, net 163 160
- ----------------------------------------------------------------------------------------
Income from continuing operations before income tax and 96 98
minority interest
Income tax benefit 1 2
- ----------------------------------------------------------------------------------------
Income from continuing operations before minority interest 97 100
Minority interest in subsidiaries' loss (income), net of tax 8 (1)
- ----------------------------------------------------------------------------------------
Income from continuing operations 105 99
Discontinued operations, net of tax (12) 9
- ----------------------------------------------------------------------------------------
Net income $ 93 $ 108
- ----------------------------------------------------------------------------------------
Average common shares outstanding 244 241
- ----------------------------------------------------------------------------------------
Basic earnings per common share
Income from continuing operations $ 0.43 $ 0.41
Discontinued operations, net of tax (0.05) 0.04
Net income $ 0.38 $ 0.45
- ----------------------------------------------------------------------------------------
Diluted earnings per common share
Income from continuing operations $ 0.43 $ 0.41
Discontinued operations, net of tax (0.05) 0.04
Net income $ 0.38 $ 0.45
- ----------------------------------------------------------------------------------------
Dividends declared per common share $ 0.590 $ 0.575
- ----------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
6
PROGRESS ENERGY, INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------------------------------
(in millions) March 31, December 31,
2005 2004
- --------------------------------------------------------------------------------------------------------
ASSETS
Utility plant
Utility plant in service $ 22,117 $ 22,103
Accumulated depreciation (9,231) (8,783)
- --------------------------------------------------------------------------------------------------------
Utility plant in service, net 12,886 13,320
Held for future use 13 13
Construction work in progress 972 799
Nuclear fuel, net of amortization 251 231
- --------------------------------------------------------------------------------------------------------
Total utility plant, net 14,122 14,363
- --------------------------------------------------------------------------------------------------------
Current assets
Cash and cash equivalents 280 56
Short-term investments 229 82
Receivables 931 911
Inventory 772 805
Deferred fuel cost 235 229
Deferred income taxes 65 111
Assets of discontinued operations - 574
Prepayments and other current assets 291 174
- --------------------------------------------------------------------------------------------------------
Total current assets 2,803 2,942
- --------------------------------------------------------------------------------------------------------
Deferred debits and other assets
Regulatory assets 1,021 1,064
Nuclear decommissioning trust funds 1,078 1,044
Diversified business property, net 1,861 1,838
Miscellaneous other property and investments 480 444
Goodwill 3,719 3,719
Intangibles, net 330 337
Other assets and deferred debits 282 265
- --------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 8,771 8,711
- --------------------------------------------------------------------------------------------------------
Total assets $ 25,696 $ 26,016
- --------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- --------------------------------------------------------------------------------------------------------
Common stock equity
Common stock without par value, 500 million shares authorized,
249 and 247 million shares issued and outstanding, respectively $ 5,428 $ 5,360
Unearned restricted shares (1 and 1 million shares, respectively) (16) (13)
Unearned ESOP shares (3 and 3 million shares, respectively (65) (76)
Accumulated other comprehensive loss (159) (164)
Retained earnings 2,475 2,526
- --------------------------------------------------------------------------------------------------------
Total common stock equity 7,663 7,633
- --------------------------------------------------------------------------------------------------------
Preferred stock of subsidiaries-not subject to mandatory redemption 93 93
Minority interest 38 36
Long-term debt, affiliate 270 270
Long-term debt, net 8,728 9,251
- --------------------------------------------------------------------------------------------------------
Total capitalization 16,792 17,283
- --------------------------------------------------------------------------------------------------------
Current liabilities
Current portion of long-term debt 1,148 349
Accounts payable 582 630
Interest accrued 165 219
Dividends declared 146 145
Short-term obligations 691 684
Customer deposits 186 180
Liabilities of discontinued operations - 149
Other current liabilities 620 703
- --------------------------------------------------------------------------------------------------------
Total current liabilities 3,538 3,059
- --------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities
Noncurrent income tax liabilities 603 625
Accumulated deferred investment tax credits 173 176
Regulatory liabilities 2,402 2,654
Asset retirement obligations 1,211 1,282
Other liabilities and deferred credits 977 937
- --------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 5,366 5,674
- --------------------------------------------------------------------------------------------------------
Commitments and contingencies (Note 14)
- --------------------------------------------------------------------------------------------------------
Total capitalization and liabilities $ 25,696 $ 26,016
- --------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
7
PROGRESS ENERGY, INC.
UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
- -----------------------------------------------------------------------------------------------------
(in millions)
Three Months Ended March 31, 2005 2004
- -----------------------------------------------------------------------------------------------------
Operating activities
Net income $ 93 $ 108
Adjustments to reconcile net income to net cash provided by operating
activities:
Discontinued operations, net of tax 12 (9)
Depreciation and amortization 276 271
Deferred income taxes 13 (7)
Investment tax credit (3) (4)
Deferred fuel cost 19 63
Other adjustments to net income 42 16
Cash provided (used) by changes in operating assets and
liabilities:
Receivables 4 50
Inventory (23) 6
Prepayments and other current assets (10) (20)
Accounts payable 38 (35)
Other current liabilities (156) (131)
Regulatory assets and liabilities (55) (7)
Other 29 66
- -----------------------------------------------------------------------------------------------------
Net cash provided by operating activities 279 367
- -----------------------------------------------------------------------------------------------------
Investing activities
Gross utility property additions (263) (242)
Diversified business property additions (49) (45)
Nuclear fuel additions (64) (39)
Proceeds from sales of subsidiaries and other investments 406 84
Purchases of short-term investments (1,840) (601)
Proceeds from sales of short-term investments 1,693 828
Other (49) (9)
- -----------------------------------------------------------------------------------------------------
Net cash used in investing activities (166) (24)
- -----------------------------------------------------------------------------------------------------
Financing activities
Issuance of common stock 60 29
Issuance of long-term debt 495 -
Net increase in short-term indebtedness 7 503
Retirement of long-term debt (216) (675)
Dividends paid on common stock (145) (141)
Other (48) (62)
- ---------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 153 (346)
- -----------------------------------------------------------------------------------------------------
Cash (used) provided by discontinued operations (42) 6
Net increase in cash and cash equivalents 224 3
Cash and cash equivalents at beginning of period 56 34
- -----------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 280 $ 37
- -----------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
8
PROGRESS ENERGY, INC.
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
A. 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 statements. Because the accompanying
consolidated interim financial statements do not include all of the
information and footnotes required by GAAP, they should be read in
conjunction with the audited financial statements for the period ended
December 31, 2004, and notes thereto included in Progress Energy's Form
10-K for the year ended December 31, 2004.
In accordance with the provisions of Accounting Principles Board Opinion
(APB) No. 28, "Interim Financial Reporting," GAAP requires companies to
apply a levelized effective tax rate to interim periods that is consistent
with the estimated annual effective tax rate. Income tax expense was
increased by $3 million and $39 million for the three months ended March
31, 2005 and 2004, respectively, in order to maintain an effective tax rate
consistent with the estimated annual rate. The income tax provisions for
the Company differ from amounts computed by applying the Federal statutory
tax rate to income before income taxes, primarily due to the recognition of
synthetic fuel tax credits.
PEC and PEF collect from customers certain excise taxes levied by the state
or local government upon the customers. PEC and PEF account for excise
taxes on a gross basis. For the three months ended March 31, 2005 and 2004,
gross receipts tax, franchise taxes and other excise taxes of approximately
$57 million and $53 million, respectively, are included in utility revenues
and taxes other than on income in the Consolidated Statements of Income.
The amounts included in the consolidated interim financial statements are
unaudited but, in the opinion of management, reflect all normal recurring
adjustments necessary to fairly present the Company's financial position
and results of operations for the interim periods. Due to seasonal weather
variations 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 with GAAP, management must
make estimates and assumptions that affect the reported amounts of assets
and liabilities, disclosure of contingent assets and liabilities at the
date of the financial statements and amounts of revenues and expenses
reflected during the reporting period. Actual results could differ from
those estimates. Certain amounts for 2004 have been reclassified to conform
to the 2005 presentation.
B. Stock-Based Compensation
The Company measures compensation expense for stock options as the
difference between the market price of its common stock and the exercise
price of the option at the grant date. The exercise price at which options
are granted by the Company equals the market price at the grant date, and
accordingly, no compensation expense has been recognized for stock option
grants. For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair
value of the Company's stock options is amortized to expense over the
options' vesting period. The following table illustrates the effect on net
income and earnings per share if the fair value method had been applied to
all outstanding and unvested awards in each period:
9
-----------------------------------------------------------------------------------------------
(in millions except per share data) Three Months Ended March 31,
2005 2004
-----------------------------------------------------------------------------------------------
Net income, as reported $ 93 $ 108
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 1 3
-----------------------------------------------------------------------------------------------
Pro forma net income $ 92 $ 105
-----------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------
Basic earnings per share
As reported $ 0.38 $ 0.45
Pro forma $ 0.38 $ 0.44
Fully diluted earnings per share
As reported $ 0.38 $ 0.45
Pro forma $ 0.38 $ 0.43
-----------------------------------------------------------------------------------------------
The Company expects to begin expensing stock options on July 1, 2005 (See
Note 2).
C. Consolidation of Variable Interest Entities
The Company consolidates all voting interest entities in which it owns a
majority voting interest and all variable interest entities for which it is
the primary beneficiary in accordance with FASB Interpretation No. 46R,
"Consolidation of Variable Interest Entities - An Interpretation of ARB No.
51" (FIN No. 46R). The Company is the primary beneficiary of and
consolidates two limited partnerships that qualify for federal affordable
housing and historic tax credits under Section 42 of the Internal Revenue
Code (Code). As of March 31, 2005, the total assets of the two entities
were $37 million, the majority of which are collateral for the entities'
obligations and are included in other current assets and miscellaneous
other property and investments in the Consolidated Balance Sheets.
The Company has an interest in a limited partnership that invests in 17
low-income housing partnerships that qualify for federal and state tax
credits. The Company also has interests in two power plants resulting from
long-term power purchase contracts. The Company has requested the necessary
information to determine if the 17 partnerships and the two power plant
owners are variable interest entities or to identify the primary
beneficiaries; all three entities declined to provide the Company with the
necessary financial information. Therefore, the Company has applied the
information scope exception in FIN No. 46R, paragraph 4(g) to the 17
partnerships and the two power plants. The Company believes that if it is
determined to be the primary beneficiary of any of these entities, the
effect of consolidating the entities would result in increases to total
assets, long-term debt and other liabilities, but would have an
insignificant or no impact on the Company's common stock equity, net
earnings or cash flows.
The Company also has interests in several other variable interest entities
for which the Company is not the primary beneficiary. These arrangements
include investments in approximately 28 limited partnerships, limited
liability corporations and venture capital funds and two building leases
with special-purpose entities. The aggregate maximum loss exposure at March
31, 2005, that the Company could be required to record in its income
statement as a result of these arrangements totals approximately $38
million. The creditors of these variable interest entities do not have
recourse to the general credit of the Company in excess of the aggregate
maximum loss exposure.
2. IMPACT OF NEW ACCOUNTING STANDARDS
PROPOSED FASB INTERPRETATION OF SFAS NO. 109, "ACCOUNTING FOR INCOME TAXES"
In July 2004, the Financial Accounting Standards Board (FASB) stated that
it plans to issue an exposure draft of a proposed interpretation of SFAS
No. 109, "Accounting for Income Taxes" (SFAS No. 109), that would address
the accounting for uncertain tax positions. The FASB has indicated that the
interpretation would require that uncertain tax benefits be probable of
being sustained in order to record such benefits in the consolidated
financial statements. The exposure draft is expected to be issued in the
second quarter of 2005. The Company cannot predict what actions the FASB
10
will take or how any such actions might ultimately affect the Company's
financial position or results of operations, but such changes could have a
material impact on the Company's evaluation and recognition of Section 29
tax credits (See Note 14).
SFAS NO. 123 (REVISED 2004), "SHARE-BASED PAYMENT" (SFAS NO. 123R)
In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No.
123, "Accounting for Stock-Based Compensation," and supersedes Accounting
Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to
Employees." The key requirement of SFAS No. 123R is that the cost of
share-based awards to employees will be measured based on an award's fair
value at the grant date, with such cost to be amortized over the
appropriate service period. Previously, entities could elect to continue
accounting for such awards at their grant date intrinsic value under APB
Opinion No. 25, and the Company made that election. The intrinsic value
method resulted in the Company recording no compensation expense for stock
options granted to employees (See Note 1B).
As written, SFAS No. 123R had an original effective date of July 1, 2005
for the Company. In April 2005, the SEC delayed the effective date for
public companies, which resulted in a required effective date of January 1,
2006 for the Company. The SEC delayed the effective date due to concerns
that implementation in mid-year could make compliance more difficult and
make comparisons of quarterly reports more difficult. The Company currently
intends to implement SFAS No. 123R on the original effective date of July
1, 2005. The Company intends to implement the standard using the required
modified prospective method. Under that method and with a July 1, 2005
implementation, the Company will record compensation expense under SFAS No.
123R for all awards it grants after July 1, 2005, and it will record
compensation expense (as previous awards continue to vest) for the unvested
portion of previously granted awards that remain outstanding at July 1,
2005. In 2004, the Company made the decision to cease granting stock
options and replaced that compensation with alternative forms of
compensation. Therefore, the amount of stock option expense expected to be
recorded in 2005 is below the amount that would have been recorded if the
stock option program had continued. The Company expects to record
approximately $3 million of pre-tax expense for stock options in 2005.
FASB INTERPRETATION NO. 47, "ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS"
On March 30, 2005, the FASB issued Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations," an interpretation of SFAS No.
143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). The
interpretation clarifies that a legal obligation to perform an asset
retirement activity that is conditional on a future event is within the
scope of SFAS No. 143. Accordingly, an entity is required to recognize a
liability for the fair value of an asset retirement obligation that is
conditional on a future event if the liability's fair value can be
reasonably estimated. The interpretation also provides additional guidance
for evaluating whether sufficient information is available to make a
reasonable estimate of the fair value. The interpretation is effective for
the Company no later than December 31, 2005. The Company has not yet
determined the impact of the interpretation on its financial position,
results of operations or liquidity.
3. DIVESTITURES
Progress Rail Divestiture
On March 24, 2005, the Company completed the sale of Progress Rail to One
Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co.
Gross cash proceeds from the sale are estimated to be $433 million,
consisting of $405 million base proceeds plus an estimated working capital
adjustment. Proceeds from the sale were used to reduce debt.
Based on the estimated gross proceeds associated with the sale of $433
million, the Company recorded an estimated after-tax loss on disposal of
$17 million during the first quarter of 2005. The Company anticipates
adjustments to the loss on the divestiture during the second quarter of
2005 related to employee benefit settlements and the finalization of the
working capital adjustment and other operating estimates.
11
The accompanying consolidated interim financial statements have been
restated for all periods presented to reflect the operations of Progress
Rail as discontinued operations in the Consolidated Statements of Income.
Interest expense has been allocated to discontinued operations based on the
net assets of Progress Rail, assuming a uniform debt-to-equity ratio across
the Company's operations. Interest expense allocated for the three months
ended March 31, 2005 and 2004 was $4 million each period. The Company
ceased recording depreciation upon classification of the assets as
discontinued operations in February 2005. After-tax depreciation expense
recorded by Progress Rail during the three months ended March 31, 2005 and
2004 was $3 million and $2 million, respectively. Results of discontinued
operations were as follows:
------------------------------------------------------------------------------
Three Months Ended
March 31,
(in millions) 2005 2004
------------------------------------------------------------------------------
Revenues $ 358 $ 239
------------------------------------------------------------------------------
Earnings before income taxes $ 8 $ 12
Income tax expense 3 3
------------------------------------------------------------------------------
Net earnings from discontinued operations 5 9
Estimated loss on disposal of discontinued operations,
including income tax benefit of $14 (17) -
------------------------------------------------------------------------------
Earnings (loss) from discontinued operations $ (12) $ 9
------------------------------------------------------------------------------
Prior to the sale of Progress Rail, the results of operations of Progress
Rail were reported one month in arrears. Accordingly, the net loss from
discontinued operations for the first quarter of 2005 includes four months
of Progress Rail's operations.
In connection with the sale, Progress Fuels and Progress Energy provided
guarantees and indemnifications of certain legal, tax and environmental
matters to One Equity Partners, LLC. See discussion of the Company's
guarantees at Note 14A.
The major balance sheet classes included in assets and liabilities of
discontinued operations in the Consolidated Balance Sheets as of December
31, 2004 are as follows:
----------------------------------------------------------
(in millions)
----------------------------------------------------------
Accounts receivable $ 172
----------------------------------------------------------
Inventory 177
----------------------------------------------------------
Other current assets 18
Total property, plant and equipment, net 174
Total other assets 33
----------------------------------------------------------
Assets of discontinued operations $ 574
----------------------------------------------------------
Accounts payable $ 112
Accrued expenses 37
----------------------------------------------------------
Liabilities of discontinued operations $ 149
----------------------------------------------------------
In February 2004, the Company sold the majority of the assets of Railcar
Ltd., a subsidiary of Progress Rail, to The Andersons, Inc. for proceeds of
approximately $82 million.
4. REGULATORY MATTERS
PEF Retail Rate Matters
Hearings on PEF's petition for recovery of $252 million of storm costs
filed with the Florida Public Service Commission (FPSC) were held from
March 30, 2005 to April 1, 2005. The FPSC is scheduled to vote on the
Company's petition on June 14, 2005, with an order expected on July 5,
2005. The Company cannot predict the outcome of this matter.
12
On May 4, 2005, a bill was approved by the Florida Legislature that would
authorize the FPSC to consider allowing the state's investor-owned
utilities to issue bonds that are secured by surcharges on utility customer
bills. These bonds would be issued for recovery of storm damage costs and
potentially to restore depleted storm reserves. The amount of funds
established for recovery is subject to the review and approval of the FPSC.
The bill will now be sent to Governor Bush for his consideration. The
Governor has indicated that he supports the bill. The Company cannot
predict the outcome of this matter.
On April 29, 2005, PEF submitted minimum filing requirements, based on a
2006 projected test year, to initiate a base rate proceeding regarding its
future base rates. In its filing, PEF has requested a $206 million annual
increase in base rates effective January 1, 2006. PEF's request for an
increase in base rates reflects an increase in operational costs with (i)
the addition of Hines 2 generation facility into base rates rather than the
Fuel Clause as was permitted under the terms of existing Stipulation and
Settlement Agreement (the Agreement), (ii) completion of the Hines 3
generation facility, (iii) the need to replenish PEF's depleted storm
reserve by adjusting the annual accrual in light of recent history on a
going-forward basis, (iv) the expected infrastructure investment necessary
to meet high customer expectations, coupled with the demands placed on
PEF's strong customer growth, (v) significant additional costs including
increased depreciation and fossil dismantlement expenses and (vi) general
inflationary pressures.
Hearings on the base rate proceeding are expected during the third quarter
of 2005 and a final decision is expected by the end of 2005. The Company
cannot predict the outcome of this matter.
The FPSC requires that PEF perform a depreciation study no less than every
four years. PEF filed a depreciation study with the FPSC on April 29, 2005,
as part of the Company's base rate filing, which will increase depreciation
expense in 2006 by $14 million and forward if approved by the FPSC. The
Company cannot predict the outcome or impact of this matter. PEF reduced
its estimated removal costs to take into account the estimates used in the
depreciation study. This resulted in a downward revision in the PEF
estimated removal costs and equal increase in accumulated depreciation of
approximately $379 million.
The FPSC requires that PEF update its cost estimate for fossil
dismantlement every four years. PEF filed an updated fossil dismantlement
study with the FPSC on April 29, 2005, as part of the Company's base rate
filing, which will increase the accrual by $10 million and what PEF
collects in base rates for fossil dismantlement in 2006 and forward if
approved by the FPSC. PEF's retail reserve for fossil plant dismantlement
was approximately $133 million at March 31, 2005. Retail accruals on PEF's
reserves for fossil dismantlement were previously suspended through
December 2005 under the terms of PEF's existing Agreement. The Company
cannot predict the outcome or impact of this matter.
The FPSC requires that PEF update its cost estimate for nuclear
decommissioning every five years. PEF filed a new site-specific estimate of
decommissioning costs for the Crystal River Nuclear Plant (CR3) with the
FPSC on April 29, 2005 as part of the Company's base rate filing. PEF's
estimate was based on prompt decommissioning. The estimate, in 2005
dollars, is $614 million and is subject to change based on a variety of
factors including, but not limited to, cost escalation, changes in
technology applicable to nuclear decommissioning and changes in federal,
state or local regulations. The cost estimate excludes the portion
attributable to other co-owners of CR3. The NRC operating license held by
PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016.
An application to extend this license 20 years is expected to be submitted
in the first quarter of 2009. As part of this new estimate and assumed
license extension, PEF reduced its ARO liability by approximately $88
million at March 31, 2005. Retail accruals on PEF's reserves for nuclear
decommissioning were previously suspended through December 2005 under the
terms of the Agreement and the new study supports a continuation of that
suspension. The Company cannot predict the outcome or impact of this
matter.
13
PEC Retail Rate Matters
On April 27, 2005, PEC filed for an increase in the fuel rate charged to
its South Carolina customers with the Public Service Commission of South
Carolina (SCPSC). PEC is asking the SCPSC to approve a $97 million, or 21
percent, increase in rates. PEC requested the increase for underrecovered
fuel costs for the previous 15 months and to meet future expected fuel
costs. This request reflects increases in the prices of coal and natural
gas. If approved, the increase would take effect July 1, 2005. The Company
cannot predict the outcome of this matter.
5. GOODWILL AND OTHER INTANGIBLE ASSETS
The Company performed the annual goodwill impairment test in accordance
with SFAS No. 142, "Goodwill and Other Intangible Assets," for the CCO
segment in the first quarter of 2005, which indicated no impairment was
necessary. The annual impairment tests for the PEC Electric and PEF
segments will be performed in the second quarter of 2005.
The changes in the carrying amount of goodwill for the periods ended March
31, 2005 and December 31, 2004, by reportable segment, are as follows:
---------------------------------------------------------------------------------------------
(in millions) PEC Electric PEF CCO Other Total
---------------------------------------------------------------------------------------------
Balance as of January 1, 2004 $ 1,922 $ 1,733 $ 64 $ 7 $ 3,726
Purchase accounting adjustment - - - (7) (7)
---------------------------------------------------------------------------------------------
Balance as of December 31, 2004 $ 1,922 $ 1,733 $ 64 $ - $ 3,719
---------------------------------------------------------------------------------------------
Balance as of March 31, 2005 $ 1,922 $ 1,733 $ 64 $ - $ 3,719
---------------------------------------------------------------------------------------------
The gross carrying amount and accumulated amortization of the Company's
intangible assets at March 31, 2005 and December 31, 2004, are as follows:
------------------------------------------------------------------------------------------------
March 31, 2005 December 31, 2004
------------------------------------------------------------------------------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
(in millions) Amount Amortization Amount Amortization
------------------------------------------------------------------------------------------------
Synthetic fuel intangibles $ 134 $ (84) $ 134 $ (80)
Power agreements acquired 188 (8) 188 (6)
Other 119 (19) 119 (18)
------------------------------------------------------------------------------------------------
Total $ 441 $ (111) $ 441 $ (104)
------------------------------------------------------------------------------------------------
Amortization expense recorded on intangible assets for the three months
ended March 31, 2005 and 2004, was $7 million and $10 million,
respectively. The estimated annual amortization expense for intangible
assets for 2005 through 2009, in millions, is approximately $35, $36, $36,
$18 and $18, respectively.
6. EQUITY AND COMPREHENSIVE INCOME
A. Earnings Per Common Share
A reconciliation of the weighted-average number of common shares
outstanding for basic and dilutive earnings per share purposes is as
follows:
---------------------------------------------------------------------------
Three Months Ended March 31,
(in millions) 2005 2004
---------------------------------------------------------------------------
Weighted-average common shares - basic 244 241
Restricted stock awards 1 1
--------------------------------------------------------------------------
Weighted-average shares - fully dilutive 245 242
---------------------------------------------------------------------------
14
B. Comprehensive Income
-------------------------------------------------------------------------------------------
Three Months Ended
March 31,
(in millions) 2005 2004
------------------------------------------------------------------------------------------
Net income $ 93 $ 108
Other comprehensive income (loss):
Reclassification adjustments included in net income:
Change in cash flow hedges (net of tax expense of
$1 and $2, respectively) 2 4
Foreign currency translation adjustments included in
discontinued operations (6) -
Minimum pension liability adjustment included in
discontinued operations (net of tax expense of $1) 1 -
Changes in net unrealized gains (losses) on cash flow hedges
(net of tax expense (benefit) of $5 and ($8), respectively) 6 (17)
Foreign currency translation adjustment and other 2 2
------------------------------------------------------------------------------------------
Other comprehensive income (loss) $ 5 $ (11)
------------------------------------------------------------------------------------------
Comprehensive income $ 98 $ 97
------------------------------------------------------------------------------------------
C. Common Stock
At December 31, 2004, the Company had approximately 63 million shares of
common stock authorized by the Board of Directors that remained unissued
and reserved. In 2002, the Board of Directors authorized meeting the
requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan
and the Investor Plus Stock Purchase Plan with original issue shares. For
the three months ended March 31, 2005, the Company issued approximately 1.3
million shares under these plans for net proceeds of approximately $58
million.
7. DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES
Changes to the Company's debt and credit facilities since December 31,
2004, discussed in Note 13 of the Company's 2004 Annual Report on Form
10-K, are described below.
In January 2005, the Company used proceeds from the issuance of commercial
paper to pay off $260 million of revolving credit agreement (RCA) loans,
which included $90 million at PEC and $170 million at PEF.
On January 31, 2005, Progress Energy, Inc. entered into a new $600 million
RCA, which expires December 30, 2005. This facility was added to provide
additional liquidity during 2005 due in part to the uncertainty of the
timing of storm restoration cost recovery from the hurricanes in Florida
during 2004. The RCA includes a defined maximum total debt to total capital
ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The RCA
also contains various cross-default and other acceleration provisions. On
February 4, 2005, $300 million was drawn under the new facility to reduce
commercial paper and pay off the remaining amount of loans outstanding
under other RCA facilities, which consisted of $160 million at Progress
Energy and $55 million at PEF. As discussed below, the maximum size of this
RCA was reduced to $300 million on March 22, 2005.
On March 22, 2005, PEC issued $300 million of First Mortgage Bonds, 5.15%
Series due 2015, and $200 million of First Mortgage Bonds, 5.70% Series due
2035. The net proceeds from the sale of the bonds were used to pay off $300
million of its 7.50% Senior Notes on April 1, 2005, and reduce the
outstanding balance of commercial paper. Pursuant to the terms of the
Progress Energy $600 million RCA, commitments were reduced to $300 million,
effective March 22, 2005.
In March 2005, Progress Energy, Inc.'s five-year credit facility was
amended to increase the maximum total debt to total capital ratio from 65%
to 68% due to the potential impacts of proposed accounting rules for
uncertain tax positions (See Note 2).
15
On March 28, 2005, PEF entered into a new $450 million RCA with a
syndication of financial institutions. The RCA will be used to provide
liquidity support for PEF's issuances of commercial paper and other
short-term obligations. The RCA will expire on March 28, 2010. The new $450
million RCA replaced PEF's $200 million three-year RCA and $200 million
364-day RCA, which were each terminated effective March 28, 2005. Fees and
interest rates under the $450 million RCA are to be determined based upon
the credit rating of PEF's long-term unsecured senior non-credit enhanced
debt, currently rated as A3 by Moody's Investor Services (Moody's) and BBB
by Standard and Poor's (S&P). The RCA includes a defined maximum total debt
to capital ratio of 65%. The RCA also contains various cross-default and
other acceleration provisions, including a cross-default provision for
defaults of indebtedness in excess of $35 million. The RCA does not include
a material adverse change representation for borrowings or a financial
covenant for interest coverage, which had been provisions in the terminated
agreements.
On March 28, 2005, PEC entered into a new $450 million RCA with a
syndication of financial institutions. The RCA will be used to provide
liquidity support for PEC's issuances of commercial paper and other
short-term obligations. The RCA will expire on June 28, 2010. The new $450
million RCA replaced PEC's $285 million three-year RCA and $165 million
364-day RCA, which were each terminated effective March 28, 2005. Fees and
interest rates under the $450 million RCA are to be determined based upon
the credit rating of PEC's long-term unsecured senior non-credit enhanced
debt, currently rated as Baa1 by Moody's and BBB by S&P. The RCA includes a
defined maximum total debt to capital ratio of 65%. The RCA also contains
various cross-default and other acceleration provisions, including a
cross-default provision for defaults of indebtedness in excess of $35
million. The RCA does not include a material adverse change representation
for borrowings, which had been a provision in the terminated agreements.
8. BENEFIT PLANS
The Company and some of its subsidiaries have a noncontributory defined
benefit retirement (pension) plan for substantially all full-time
employees. The Company also has supplementary defined benefit pension plans
that provide benefits to higher-level employees. In addition to pension
benefits, the Company and some of its subsidiaries provide contributory
other postretirement benefits (OPEB), including certain health care and
life insurance benefits, for retired employees who meet specified criteria.
The components of the net periodic benefit cost for the three months ended
March 31 are:
----------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefits Benefits
----------------------- ----------------------
(in millions) 2005 2004 2005 2004
----------------------------------------------------------------------------------------------
Service cost $ 15 $ 13 $ 3 $ 4
Interest cost 29 28 8 8
Expected return on plan assets (37) (37) (1) (1)
Amortization of actuarial loss 6 5 1 1
Other amortization, net 1 - - 1
----------------------------------------------------------------------------------------------
Net periodic cost $ 14 $ 9 $ 11 $ 13
Additional cost / (benefit) recognition (a) (4) (4) 1 1
----------------------------------------------------------------------------------------------
Net periodic cost recognized $ 10 $ 5 $ 12 $ 14
----------------------------------------------------------------------------------------------
(a) Relates to the acquisition of FPC. See Note 17B of Progress Energy's
Form 10-K for year ended December 31, 2004.
9. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
Progress Energy and its subsidiaries are exposed to various risks related
to changes in market conditions. The Company has 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 its risk policy, the Company 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
16
contract. The Company minimizes such risk by performing credit reviews
using, among other things, publicly available credit ratings of such
counterparties. See Note 18 to the Company's Annual Report on Form 10-K for
the year ended December 31, 2004.
A. Commodity Derivatives
General
Most of the Company's commodity contracts are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair
value loss transition adjustment pursuant to the provisions of DIG Issue
C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and
Closely Related in Paragraph 10(b) regarding Contracts with a Price
Adjustment Feature." The related liability is being amortized to earnings
over the term of the related contract (See Note 12). At March 31, 2005 and
December 31, 2004, the remaining liability was $25 million and $26 million,
respectively.
Economic Derivatives
Derivative products, primarily electricity and natural gas 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 Company manages open positions with strict policies that limit its
exposure to market risk and require daily reporting to management of
potential financial exposures. The Company recorded a $2 million pre-tax
gain and a $12 million pre-tax loss on such contracts for the three months
ended March 31, 2005 and 2004, respectively. The Company did not have
material outstanding positions in such contracts at March 31, 2005 and
December 31, 2004.
PEF has derivative instruments related to its exposure to price
fluctuations on fuel oil purchases. At March 31, 2005, the fair values of
these instruments were a $34 million short-term derivative asset position
included in other current assets and a $23 million long-term derivative
asset position included in other assets and deferred debits. At December
31, 2004, the fair values of these instruments were a $2 million long-term
derivative asset position included in other assets and deferred debits and
a $5 million short-term derivative liability position included in other
current liabilities. These instruments receive regulatory accounting
treatment. Unrealized gains and losses are recorded in regulatory
liabilities and regulatory assets, respectively.
Cash Flow Hedges
Progress Energy's subsidiaries designate a portion of commodity derivative
instruments as cash flow hedges under SFAS No. 133. The objective for
holding these instruments is to hedge exposure to market risk associated
with fluctuations in the price of natural gas for the Company's forecasted
purchases and sales. Realized gains and losses are recorded net in
operating revenues or operating expenses, as appropriate. The ineffective
portion of commodity cash flow hedges for the three months ending March 31,
2005 and 2004 was not material to the Company's results of operations.
The fair values of commodity cash flow hedges at March 31, 2005 and
December 31, 2004 were as follows:
--------------------------------------------------------
(in millions) March 31, December 31,
2005 2004
--------------------------------------------------------
Fair value of assets $ 19 $ -
Fair value of liabilities (26) (15)
--------------------------------------------------------
Fair value, net $ (7) $ (15)
--------------------------------------------------------
17
The following table presents selected information related to the Company's
commodity cash flow hedges at March 31, 2005:
------------------------------------------------------------------------------------
Accumulated Other Portion Expected to
Comprehensive be Reclassified to
(term in years/ Maximum Income/(Loss), net of Earnings during the
millions of dollars) Term(a) tax Next 12 Months(b)
------------------------------------------------------------------------------------
Commodity cash flow
hedges 10 $ (5) $ (16)
------------------------------------------------------------------------------------
(a) Hedges in fair value liability positions have a maximum term of less
than two years and hedges in fair value asset positions have a maximum term
of 10 years.
(b) Due to the volatility of the commodities markets, the value in
accumulated other comprehensive income/(loss) (OCI) is subject to change
prior to its reclassification into earnings.
B. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
The Company uses cash flow hedging strategies to hedge variable interest
rates on long-term and short-term debt and to hedge interest rates with
regard to future fixed-rate debt issuances. The Company uses fair value
hedging strategies to manage its exposure to fixed interest rates on
long-term debt. 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 risk in these transactions is the cost of
replacing the agreements at current market rates.
The fair values of interest rate hedges at March 31, 2005 and December 31,
2004 were as follows:
------------------------------------------------------------------
March 31, December 31,
(in millions) 2005 2004
------------------------------------------------------------------
Interest rate cash flow hedges $ 2 $ (2)
Interest rate fair value hedges $ - $ 3
------------------------------------------------------------------
Cash Flow Hedges
Gains and losses from cash flow hedges are recorded in OCI and amounts
reclassified to earnings are included in net interest charges as the hedged
transactions occur. Amounts in OCI related to terminated hedges are
reclassified to earnings as the hedged interest payments occur. The
ineffective portion of interest rate cash flow hedges for the three months
ending March 31, 2005 and 2004 was not material to the Company's results of
operations
The following table presents selected information related to the Company's
interest rate cash flow hedges included in OCI at March 31, 2005:
-------------------------------------------------------------------------------------
Accumulated Other Portion Expected to
Comprehensive be Reclassified to
(term in years/ Maximum Income/(Loss), net of Earnings during the
millions of dollars) Term tax(a) Next 12 Months(b)
-------------------------------------------------------------------------------------
Interest rate cash
flow hedges 1 $ (15) $ (3)
-------------------------------------------------------------------------------------
(a) Includes amounts related to terminated hedges.
(b) Actual amounts that will be reclassified to earnings may vary from the
expected amounts presented above as a result of changes in interest rates.
As of March 31, 2005 and December 31, 2004, the Company had $275 million
notional and $331 million notional, respectively, of interest rate cash
flow hedges.
18
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. As of March 31, 2005 and
December 31, 2004, the Company had $150 million notional of interest rate
fair value hedges.
10. SEVERANCE COSTS
On February 28, 2005, as part of a previously announced cost management
initiative, the Company approved a workforce restructuring which is
expected to be completed in September 2005 and result in a reduction of
approximately 450 positions. The cost management initiative is designed to
permanently reduce by $75 million to $100 million the projected growth in
the Company's annual operation and maintenance (O&M) expenses by the end of
2007. In addition to the workforce restructuring, the cost management
initiative includes a voluntary enhanced retirement program. In connection
with this initiative, the Company currently expects to incur estimated
pre-tax charges of approximately $210 million for severance and
postretirement benefits as described below. In addition, the Company
expects to incur certain incremental costs other than severance and
postretirement benefits for recruiting, training and staff augmentation
activities that cannot be quantified at this time.
The Company recorded $31 million of expense during the first quarter of
2005 for the estimated severance benefits to be paid as a result of the
approximate number of positions to be eliminated under the restructuring
and due to the implementation of an automated meter reading initiative at
PEF. These amounts will be paid over time and are subject to revision in
future quarters based on the impact of the voluntary enhanced retirement
program. The severance expenses are primarily included in O&M expense on
the Consolidated Statements of Income.
The activity in the severance liability is as follows:
--------------------------------------------------------
(in millions)
--------------------------------------------------------
Balance as of January 1, 2005 $ 5
Severance Costs Accrued 31
Payments (1)
--------------------------------------------------------
Balance as of March 31, 2005 $ 35
--------------------------------------------------------
The Company has estimated that an additional $180 million charge will be
recognized in the second quarter of 2005 that relates primarily to
postretirement benefits that will be paid over time to those eligible
employees who elected to participate in the voluntary enhanced retirement
program. Approximately 3,500 of the Company's 12,300 employees were
eligible to participate in the voluntary enhanced retirement program. The
results from the employee elections indicate that 1,447 of the Company's
employees have elected to participate in the voluntary enhanced retirement
program. The cost management initiative charges could change significantly
primarily due to the demographics of the specific employees who elected
enhanced retirement and its impact on the postretirement benefit actuarial
studies.
11. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The Company currently provides services through the following business
segments: PEC Electric, PEF, Fuels, CCO and Synthetic Fuels. Prior to 2005,
Rail Services was reported as a separate segment. In connection with the
divestiture of Progress Rail (see Note 3), the operations of Rail Services
were reclassified to discontinued operations in the first quarter of 2005
and therefore are not included in the results from continuing operations
during the periods reported. In addition, Synthetic Fuel activities were
reported in the Fuels segment prior to 2005 and now are considered a
reportable segment. These reportable segment changes reflect the current
reporting structure. For comparative purposes, the prior year results have
been restated to align with the current presentation.
19
PEC Electric and PEF are primarily engaged in the generation, transmission,
distribution and sale of electric energy in portions of (i) North Carolina
and South Carolina and (ii) Florida, respectively. These electric
operations are subject to the rules and regulations of the FERC, the NCUC,
the SCPSC, the FPSC and the United States Nuclear Regulatory Commission
(NRC). These electric operations also distribute and sell electricity to
other utilities, primarily on the east coast of the United States.
Fuels' operations, which are located throughout the United States, are
involved in natural gas drilling and production, coal terminal services,
coal mining and fuel transportation and delivery.
CCO's operations, which are located primarily in Georgia, North Carolina
and Florida, include nonregulated electric generation operations and
marketing activities.
Synthetic Fuel operations include the production and sale of synthetic fuel
as defined under the Internal Revenue Code and the operation of synthetic
fuel facilities for outside parties. These facilities are located in West
Virginia, Virginia and Kentucky. See Note 14 for more information.
In addition to these reportable operating segments, the Company has
Corporate and other activities that include holding company and service
company operations as well as other nonregulated business areas. These
nonregulated business areas include telecommunications and energy service
operations and other nonregulated subsidiaries that do not separately meet
the disclosure requirements of SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information." The profit or loss of the
identified segments plus the loss of Corporate and Other represents the
Company's total income from continuing operations.
------------------------------------------------------------------------------------------------------------
Revenues
-----------------------------------------------
(in millions) Unaffiliated Intersegment Total Income from Assets
Continuing
Operations
------------------------------------------------------------------------------------------------------------
FOR THE THREE MONTHS
ENDED MARCH 31, 2005
--------------------------
PEC Electric $ 935 $ - $ 935 $ 116 $ 10,953
PEF 848 - 848 43 7,663
Fuels 136 307 443 10 721
CCO 65 - 65 (5) 1,699
Synthetic Fuels 198 - 198 (1) 302
Corporate and Other 16 102 118 (58) 17,778
Eliminations - (409) (409) - (13,420)
------------------------------------------------------------------------------------------------------------
Consolidated totals $ 2,198 $ - $ 2,198 $ 105 $ 25,696
------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------
FOR THE THREE MONTHS
ENDED MARCH 31, 2004
-
--------------------------
PEC Electric $ 901 $ - $ 901 $ 116
PEF 784 - 784 49
Fuels 98 269 367 10
CCO 33 - 33 (8)
Synthetic Fuels 172 4 176 36
Corporate and Other 18 97 115 (104)
Eliminations - (370) (370) -
----------------------------------------------------------------------------------------------
Consolidated totals $ 2,006 $ - $ 2,006 $ 99
----------------------------------------------------------------------------------------------
20
12. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income and other income and
expense items as discussed below. The components of other, net as shown on
the accompanying Consolidated Statements of Income are as follows:
---------------------------------------------------------------------------------
Three Months Ended
March 31,
(in millions) 2005 2004
---------------------------------------------------------------------------------
Other income
Nonregulated energy and delivery services income $ 6 $ 6
DIG Issue C20 amortization (See Note 9) 1 2
Investment gains 2 2
AFUDC equity 3 2
Other 7 5
---------------------------------------------------------------------------------
Total other income $ 19 $ 17
---------------------------------------------------------------------------------
Other expense
Nonregulated energy and delivery services expenses $ 5 $ 4
Donations 4 7
Contingent value obligations unrealized loss - 7
Loss from equity investments 3 2
Write-off of non-trade receivables - 7
Other 5 12
---------------------------------------------------------------------------------
Total other expense $ 17 $ 39
---------------------------------------------------------------------------------
Other, net $ 2 $ (22)
---------------------------------------------------------------------------------
Nonregulated energy and delivery services include power protection services
and mass-market programs (surge protection, appliance services and area
light sales) and delivery, transmission and substation work for other
utilities.
13. ENVIRONMENTAL MATTERS
The Company is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters. See Note 22 of the Company's 2004 Annual Report on
Form 10-K for a more detailed, historical discussion of these federal,
state, and local regulations.
HAZARDOUS AND SOLID WASTE MANAGEMENT
The provisions of the Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended (CERCLA), authorize the EPA to
require the cleanup of hazardous waste sites. This statute imposes
retroactive joint and several liabilities. Some states, including North and
South Carolina and Florida, have similar types of legislation. The Company
and its subsidiaries are periodically notified by regulators, including the
EPA and various state agencies, of their involvement or potential
involvement in sites that may require investigation and/or remediation.
There are presently several sites with respect to which the Company has
been notified by the EPA, the State of North Carolina or the State of
Florida of its potential liability, as described below in greater detail.
The Company also is currently in the process of assessing potential costs
and exposures at other sites. For all sites, as the assessments are
developed and analyzed, the Company will accrue costs for the sites to the
extent the costs are probable and can be reasonably estimated. A discussion
of sites by legal entity follows.
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 potentially responsible parties (PRPs) at
several manufactured gas plant (MGP) sites.
21
PEC, PEF and Progress Fuels Corporation have filed claims with the
Company's general liability insurance carriers to recover costs arising
from actual or potential environmental liabilities. Some claims have been
settled and others are still pending. While the Company cannot predict the
outcome of these matters, the outcome is not expected to have a material
effect on the consolidated financial position or results of operations.
PEC
There are nine former MGP sites and a number of other sites associated with
PEC that have required or are anticipated to require investigation and/or
remediation.
During the fourth quarter of 2004, the EPA advised PEC that it had been
identified as a PRP at the Ward Transformer site located in Raleigh, North
Carolina. The EPA offered PEC and 34 other PRPs the opportunity to
negotiate cleanup of the site and reimbursement of less than $2 million to
the EPA for EPA's past expenditures in addressing conditions at the site.
Although a loss is considered probable, an agreement among PRPs has not
been reached; consequently, it is not possible at this time to reasonably
estimate the total amount of PEC's obligation for remediation of the Ward
Transformer site.
As of March 31, 2005 and December 31, 2004, PEC's accruals for probable and
estimable costs related to various environmental sites, which are included
in other liabilities and deferred credits and are expected to be paid out
over many years, were:
---------------------------------------------------------------------------------------
(in millions) March 31, 2005 December 31, 2004
---------------------------------------------------------------------------------------
Insurance fund $ 5 $ 7
Transferred from North Carolina Natural Gas 2 2
Corporation at time of sale
---------------------------------------------------------------------------------------
Total accrual for environmental sites $ 7 $ 9
---------------------------------------------------------------------------------------
The insurance fund in the table above was established when PEC received
insurance proceeds to address costs associated with environmental
liabilities related to its involvement with some sites. All eligible
expenses related to these are charged against a specific fund containing
these proceeds. PEC made no additional accruals, spent approximately $2
million related to environmental remediation and received no insurance
proceeds for the three months ended March 31, 2005.
This accrual has been recorded on an undiscounted basis. PEC measures its
liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
The process often involves assessing and developing cost-sharing
arrangements with other PRPs. PEC will accrue costs for the sites to the
extent its 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, PEC cannot determine the total costs that may be
incurred in connection with the remediation of all sites at this time. It
is anticipated that sufficient information will become available for
several sites during 2005 to allow a reasonable estimate of PEC's
obligation for those sites to be made.
On March 30, 2005, the North Carolina Division of Water Quality renewed a
PEC permit for the continued use of coal combustion products generated at
any of the Company's coal-fired plants located in the state. The Company
has reviewed the permit conditions, which could significantly restrict the
reuse of coal ash and result in higher ash management costs and plans to
adjudicate the permit conditions. The Company cannot predict the outcome of
this matter.
22
PEF
As of March 31, 2005 and December 31, 2004, PEF's accruals for probable and
estimable costs related to various environmental sites, which are included
in other liabilities and deferred credits and are expected to be paid out
over many years, were:
-------------------------------------------------------------------------------------------------
(in millions) March 31, 2005 December 31, 2004
-------------------------------------------------------------------------------------------------
Remediation of distribution and substation transformers $ 25 $ 27
MGP and other sites 18 18
-------------------------------------------------------------------------------------------------
Total accrual for environmental sites $ 43 $ 45
-------------------------------------------------------------------------------------------------
PEF has received approval from the FPSC for recovery of costs associated
with the remediation of distribution and substation transformers through
the Environmental Cost Recovery Clause (ECRC). Under agreements with the
Florida Department of Environmental Protection (FDEP), PEF is in the
process of examining distribution transformer sites and substation sites
for potential equipment integrity issues that could result in the need for
mineral oil impacted soil remediation. PEF has reviewed a number of
distribution transformer sites and all substation sites. PEF expects to
have completed its review of distribution transformer sites by the end of
2007. Should further sites be identified, PEF believes that any estimated
costs would also be recovered through the ECRC. For the three months ended
March 31, 2005, PEF made no additional accruals and spent approximately $2
million related to the remediation of transformers. PEF has recorded a
regulatory asset for the probable recovery of these costs through the ECRC.
The amounts for MGP and other sites, in the table above, relate to two
former MGP sites and other sites associated with PEF that have required or
are anticipated to require investigation and/or remediation. In 2004, PEF
received approximately $12 million in insurance claim settlement proceeds
and recorded a related accrual for associated environmental expenses, as
these insurance proceeds are restricted for use in addressing costs
associated with environmental liabilities. PEF made no additional accruals
or material expenditures and received no insurance proceeds, for the three
months ended March 31, 2005.
These accruals have been recorded on an undiscounted basis. PEF measures
its liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often includes assessing and developing cost-sharing
arrangements with other PRPs. 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 advanced to the stage where a
reasonable estimate of the remediation costs can be made, at this time PEF
is unable to provide an estimate of its obligation to remediate these sites
beyond what is currently accrued. As more activity occurs at these sites,
PEF will assess the need to adjust the accruals. It is anticipated that
sufficient information will become available in 2005 to make a reasonable
estimate of PEF's obligation for one of the MGP sites.
In Florida, a risk-based corrective action (RBCA, known as Global RBCA)
rule was developed by the FDEP and adopted at the February 2, 2005,
Environmental Review Commission hearing. Risk-based corrective action
generally means that the corrective action prescribed for contaminated
sites can correlate to the level of human health risk imposed by the
contamination at the property. The Global RBCA rule expands the use of the
risk-based corrective action to all contaminated sites in the state that
are not currently in one of the state's waste cleanup programs and has the
potential for making future cleanups in Florida more costly to complete.
The effective date of the Global RBCA rule was April 17, 2005. The Company
is in the process of assessing the impact of this rule.
Florida Progress Corporation
In 2001, FPC established an accrual to address indemnities and retained an
environmental liability associated with the sale of its Inland Marine
Transportation business. In 2003, the accrual was reduced to $4 million
based on a change in estimate. As of March 31, 2005 and December 31, 2004,
the remaining accrual balance was approximately $3 million. Expenditures
related to this liability were not material to the Company's financial
condition for the three months ended March 31, 2005. FPC measures its
liability for these exposures based on estimable and probable remediation
scenarios.
23
Certain historical sites are being addressed voluntarily by FPC. An
immaterial accrual has been established to address investigation expenses
related to these sites. At this time, the Company cannot determine the
total costs that may be incurred in connection with these sites.
Progress Rail
On March 24, 2005, the Company closed on the sale of its Progress Rail
subsidiary. In connection with the sale, the Company incurred indemnity
obligations related to certain pre-closing liabilities, including certain
environmental matters (see discussion under Guarantees in Note 14A).
AIR QUALITY
The Company is subject to various current and proposed federal, state, and
local environmental compliance laws and regulations, which may result in
increased planned capital expenditures and operating and maintenance costs.
Significant updates to these laws and regulations and related impacts to
the Company since December 31, 2004, are discussed below. Additionally,
Congress is considering legislation that would require reductions in air
emissions of NOx, SO2, carbon dioxide and mercury. Some of these proposals
establish nationwide caps and emission rates over an extended period of
time. This national multi-pollutant approach to air pollution control could
involve significant capital costs that could be material to the Company's
consolidated financial position or results of operations. Control equipment
that will be installed on North Carolina fossil generating facilities as
part of the North Carolina Clean Smokestacks Act (Smokestacks Act), enacted
in 2002 and discussed below, may address some of the issues outlined above.
However, the Company cannot predict the outcome of the matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether changes
at those facilities were subject to New Source Review requirements or New
Source Performance Standards under the Clean Air Act. The Company was asked
to provide information to the EPA as part of this initiative and cooperated
in supplying the requested information. The EPA initiated civil enforcement
actions against other unaffiliated utilities as part of this initiative.
Some of these actions resulted in settlement agreements calling for
expenditures by these unaffiliated utilities in excess of $1.0 billion.
These settlement agreements have generally called for expenditures to be
made over extended time periods, and some of the companies may seek
recovery of the related cost through rate adjustments or similar
mechanisms.
Total capital expenditures to meet the requirements of the final rule under
Section 110 of the Clean Air Act (NOx SIP Call) in North and South Carolina
could reach approximately $370 million. This amount also includes the cost
to install NOx controls under North Carolina's and South Carolina's
programs to comply with the federal 8-hour ozone standard. However, further
technical analysis and rulemaking may result in requirements for additional
controls at some units. To date, the Company has spent approximately $303
million related to these projected amounts. Increased operation and
maintenance costs relating to the NOx SIP Call are not expected to be
material to the Company's results of operations. Further controls are
anticipated as electricity demand increases. Parties unrelated to the
Company have undertaken efforts to have Georgia excluded from the rule and
its requirements. Georgia has not yet submitted a state implementation plan
to comply with the Section 110 NOx SIP Call. The Company cannot predict the
outcome of this matter for the impact to its nonregulated operations in
Georgia.
The Company projects that its capital costs to meet emission targets for
NOx and SO2 from coal-fired power plants under the Smokestacks Act, will
total approximately $895 million by the end of 2013. PEC has expended
approximately $141 million of these capital costs through March 31, 2005.
The law requires PEC to amortize 70% of the original cost estimate of $813
million, during a five-year rate freeze period. PEC recognized amortization
of $27 million for the three months ended March 31, 2005, and has
recognized $275 million in cumulative amortization through March 31, 2005.
The remaining amortization requirement will be recorded over the future
period ending December 31, 2007. The law permits PEC the flexibility to
vary the amortization schedule for recording the compliance costs from no
amortization expense up to $174 million per year. The NCUC will hold a
hearing prior to December 31, 2007, to determine cost recovery amounts for
2008 and future periods. O&M expense will significantly increase due to the
24
additional materials, personnel and general maintenance associated with the
equipment. O&M expenses are recoverable through base rates, rather than as
part of this program. The Company cannot predict the future regulatory
interpretation, implementation or impact of this law.
On March 10, 2005, the EPA issued the final Clean Air Interstate Rule
(CAIR). The EPA's rule requires 28 states and the District of Columbia,
including North Carolina, South Carolina, Georgia and Florida, to reduce
NOx and SO2 emissions in order to attain state NOx and SO2 emissions
levels. The Company is reviewing the final rule. Installation of additional
air quality controls is likely to be needed to meet the CAIR requirements.
The Company is in the process of determining compliance plans and the cost
to comply with the rule. The air quality controls already installed for
compliance with the NOx SIP Call and currently planned by the Company to
comply with the Smokestacks Act will reduce the costs required to meet the
CAIR requirements for the Company's North Carolina units.
On March 15, 2005, the EPA finalized two separate but related rules: the
Clean Air Mercury Rule (CAMR) that sets emissions limits to be met in two
phases and encourages a cap and trade approach to achieving those caps, and
a de-listing rule that eliminated any requirement to pursue a maximum
achievable control technology (MACT) approach for limiting mercury
emissions from coal-fired power plants. NOx and SO2 controls also are
effective in reducing mercury emissions, however, according to the EPA the
second phase cap reflects a level of mercury emissions reduction that
exceeds the level that would be achieved solely as a co-benefit of
controlling NOx and SO2 under CAIR. The Company is in the process of
determining compliance plans and the cost to comply with the CAMR.
Installation of additional air quality controls is likely to be needed to
meet the CAMR's requirements. The de-listing rule has been challenged by a
number of parties; the resolution of the challenges could impact the
Company's final compliance plans and costs.
In conjunction with the proposed mercury rule, the EPA proposed a MACT
standard to regulate nickel emissions from residual oil-fired units. The
EPA withdrew the proposed nickel rule in March 2005.
PEF is filing a petition through the ECRC program for recovery of costs for
development and implementation of an integrated strategy to comply with the
CAIR and CAMR. PEF is developing an integrated compliance strategy for the
CAIR and CAMR rules because NOx and SO2 controls also are effective in
reducing mercury emissions. PEF estimates the program costs for the
remainder of 2005 to be approximately $2 million for preliminary
engineering activities and strategy development work necessary to determine
the Company's integrated compliance strategy. PEF projects approximately
$62 million in program costs for 2006. These costs may increase or decrease
depending upon the results of the engineering and strategy development
work. Among other things, subsequent rule interpretations, equipment
availability, or the unexpected acceleration of the initial NOx or other
compliance dates could require acceleration of some projects and therefore
result in additional costs in 2005 and 2006. PEF expects to incur
significant additional capital and O&M costs to achieve compliance with the
CAIR and CAMR through 2015 and beyond. The timing and extent of the costs
for future projects will depend upon the final compliance strategy.
In March 2004, the North Carolina Attorney General filed a petition with
the EPA under Section 126 of the Clean Air Act, asking the federal
government to force coal-fired power plants in 13 other states, including
South Carolina, to reduce their NOx and SO2 emissions. The state of North
Carolina contends these out-of-state emissions interfere with North
Carolina's ability to meet national air quality standards for ozone and