EXHIBIT 99
INDEPENDENT AUDITORS' REPORT
- ----------------------------
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets of Progress
Energy, Inc. and subsidiaries (the Company) as of December 31, 2001 and 2000,
and the related consolidated statements of income, changes in common stock
equity, and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We did not audit the financial statements of
Florida Progress Corporation (a consolidated subsidiary since November 30,
2000) for the year ended December 31, 2000, which statements reflect total
assets constituting 31% of the related consolidated total assets as of December
31, 2000. Those financial statements were audited by other auditors whose
report has been furnished to us, and our opinion, insofar as it relates to the
amounts included in the Florida Progress Corporation, is based solely upon the
report of such other auditors.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, based upon our audits and the report of the other auditors,
such consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2001 and
2000, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 15, 2002
Independent Auditors' Report
To the Board of Directors of Florida Progress Corporation:
We have audited the consolidated balance sheet and schedule of capitalization
of Florida Progress Corporation and subsidiaries as of December 31, 2000 (not
separately presented herein). These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
The consolidated financial statements referred to in the introductory paragraph
have been prepared based on the Company's historical cost basis and do not
include any "push down" of Progress Energy, Inc.'s acquisition cost basis as a
result of Progress Energy, Inc.'s acquisition of the Company on November 30,
2000.
In our opinion, the consolidated balance sheet and schedule of capitalization
present fairly, in all material respects, the financial position of Florida
Progress Corporation and subsidiaries as of December 31, 2000, in conformity
with accounting principles generally accepted in the United States of America.
/s/ KPMG LLP
St. Petersburg, Florida
February 15, 2001
CONSOLIDATED STATEMENTS of INCOME
- ---------------------------------
Years ended December 31
(In thousands, except per share data) 2001 2000 1999
- ----------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 6,556,561 $ 3,549,821 $ 3,146,158
Natural gas 321,385 324,499 98,903
Diversified businesses 1,583,513 229,093 119,866
- ----------------------------------------------------------------------------------------------
Total Operating Revenues 8,461,459 4,103,413 3,364,927
---------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 1,559,998 686,754 581,340
Purchased power 868,078 364,977 365,425
Gas purchased for resale 243,451 250,902 67,465
Other operation and maintenance 1,246,835 823,549 682,407
Depreciation and amortization 1,090,178 754,748 503,105
Taxes other than on income 383,824 165,393 142,741
Diversified businesses 1,825,320 352,992 174,589
- ----------------------------------------------------------------------------------------------
Total Operating Expenses 7,217,684 3,399,315 2,517,072
- ----------------------------------------------------------------------------------------------
Operating Income 1,243,775 704,098 847,855
- ----------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 22,206 26,984 10,336
Impairment of investments (164,183) - -
Gain on sale of assets - 200,000 -
Other, net (27,018) 12,338 (41,018)
- ----------------------------------------------------------------------------------------------
Total Other Income (Expense) (168,995) 239,322 (30,682)
- ----------------------------------------------------------------------------------------------
Interest Charges
Long-term debt 592,477 237,494 180,676
Other interest charges 110,355 45,459 10,298
Allowance for borrowed funds used during construction (18,019) (20,668) (11,510)
- ----------------------------------------------------------------------------------------------
Total Interest Charges, Net 684,813 262,285 179,464
- ----------------------------------------------------------------------------------------------
Income before Income Taxes 389,967 681,135 637,709
Income Tax Expense (Benefit) (151,643) 202,774 258,421
- ----------------------------------------------------------------------------------------------
Net Income $ 541,610 $ 478,361 $ 379,288
==============================================================================================
Average Common Shares Outstanding 204,683 157,169 148,344
==============================================================================================
Basic Earnings per Common Share $ 2.65 $ 3.04 $ 2.56
==============================================================================================
Diluted Earnings per Common Share $ 2.64 $ 3.03 $ 2.55
==============================================================================================
Dividends Declared per Common Share $ 2.135 $ 2.075 $ 2.015
==============================================================================================
See Notes to consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
- ---------------------------
(In thousands, except share amounts) December 31
Assets 2001 2000
- --------------------------------------------------------------------------------------------------
Utility Plant
Electric utility plant in service $ 19,176,021 $ 18,124,036
Gas utility plant in service 491,903 378,464
Accumulated depreciation (10,096,412) (9,350,235)
- --------------------------------------------------------------------------------------------------
Utility plant in service, net 9,571,512 9,152,265
Held for future use 15,380 16,302
Construction work in progress 1,065,154 1,043,439
Nuclear fuel, net of amortization 262,869 224,692
- --------------------------------------------------------------------------------------------------
Total Utility Plant, Net 10,914,915 10,436,698
- --------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 54,419 101,296
Accounts receivable 944,753 925,911
Taxes receivable 32,325 -
Inventory 886,747 420,985
Deferred fuel cost 146,652 217,806
Prepayments 36,150 50,040
Assets held for sale, net - 747,745
Other current assets 226,947 192,347
- --------------------------------------------------------------------------------------------------
Total Current Assets 2,327,993 2,656,130
- --------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 455,325 613,200
Nuclear decommissioning trust funds 822,821 811,998
Diversified business property, net 1,073,046 729,662
Miscellaneous other property and investments 456,880 598,235
Goodwill, net 3,690,210 3,652,429
Prepaid pension costs 489,600 373,151
Other assets and deferred debits 509,001 239,198
- --------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,496,883 7,017,873
- --------------------------------------------------------------------------------------------------
Total Assets $ 20,739,791 $ 20,110,701
===================================================================================================
Capitalization and Liabilities
- ---------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500,000,000 shares authorized,
218,725,352 and 206,089,047 shares issued and outstanding,
respectively $ 4,121,194 $ 3,621,610
Unearned restricted shares (674,511 and 653,344 shares,
respectively) (13,701) (12,708)
Unearned ESOP shares (5,199,388 and 5,782,376 shares,
respectively) (114,385) (127,211)
Accumulated other comprehensive loss (32,180) -
Retained earnings 2,042,605 1,942,510
- --------------------------------------------------------------------------------------------------
Total common stock equity 6,003,533 5,424,201
- --------------------------------------------------------------------------------------------------
Preferred stock of subsidiaries-not subject to mandatory redemption 92,831 92,831
Long-term debt 9,483,745 5,890,099
- --------------------------------------------------------------------------------------------------
Total capitalization 15,580,109 11,407,131
- --------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 688,052 184,037
Accounts payable 709,906 828,568
Interest accrued 212,387 121,433
Dividends declared 117,857 107,645
Short-term obligations 77,529 3,972,674
Other current liabilities 585,865 448,302
- --------------------------------------------------------------------------------------------------
Total Current Liabilities 2,391,596 5,662,659
- --------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,434,506 1,807,192
Accumulated deferred investment tax credits 226,382 261,255
Regulatory liabilities 287,138 316,576
Other liabilities and deferred credits 820,060 655,888
- --------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,768,086 3,040,911
- --------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 20)
- --------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 20,739,791 $ 20,110,701
==================================================================================================
See Notes to consolidated financial statements.
CONSOLIDATED STATEMENTS of CASH FLOWS
- -------------------------------------
Years ended December 31
(In thousands) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 541,610 $ 478,361 $ 379,288
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of assets and investments (Note 1J) 208,983 - -
Depreciation and amortization 1,189,171 846,279 592,001
Deferred income taxes (366,490) (95,366) (32,495)
Investment tax credit (22,895) (18,136) (10,299)
Gain on sale of assets - (200,000) -
Change in deferred fuel 72,529 (76,704) (39,052)
Net (increase) decrease in accounts receivable 210,871 (122,640) (33,322)
Net (increase) decrease in inventories (295,874) 13,726 (17,576)
Net (increase) decrease in prepaids and other current assets (2,876) 60,727 (117,250)
Net increase (decrease) in accounts payable (273,768) 242,902 24,555
Net increase (decrease) in other current liabilities 129,124 (142,551) 7,436
Other 54,614 (48,920) 75,867
- -----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,444,999 937,678 829,153
- -----------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (1,216,481) (950,198) (689,054)
Nuclear fuel additions (115,663) (59,752) (75,641)
Acquisition of Florida Progress Corporation - (3,461,917) -
Net proceeds from sale of assets 53,010 212,825 -
Contributions to nuclear decommissioning trust (50,649) (32,391) (30,825)
Diversified business property additions (349,670) (157,628) (157,802)
Investments in non-utility activities (110) (89,351) (48,265)
- -----------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (1,679,563) (4,538,412) (1,001,587)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net 488,290 - -
Issuance of long-term debt 4,564,243 783,052 400,970
Net increase (decrease) in commercial paper reclassified to long-tem debt (121,880) 123,697 268,500
Net increase (decrease) in short-term indebtedness (3,896,182) 3,658,374 70,600
Net increase (decrease) in cash provided by checks drawn in excess of bank balances (45,372) 115,337 (117,643)
Retirement of long-term debt (322,207) (710,373) (113,335)
Dividends paid on common stock (432,078) (368,004) (293,704)
Other (47,127) (66) 6,169
- -----------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Financing Activities 187,687 3,602,017 221,557
- -----------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (46,877) 1,283 49,123
- -----------------------------------------------------------------------------------------------------------------------------------
Increase in Cash from Acquisition (See Noncash Activities) - 20,142 1,876
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of the Year 101,296 79,871 28,872
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 54,419 $ 101,296 $ 79,871
====================================================================================================================================
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest $ 588,127 $ 244,224 $ 174,101
income taxes $ 127,427 $ 367,665 $ 284,535
Noncash Activities
. On July 15, 1999, the Company purchased all outstanding shares of North
Carolina Natural Gas Corporation (NCNG) through the issuance of
approximately $360 million in common stock.
. On June 28, 2000, Caronet, a wholly-owned subsidiary of the Company,
contributed net assets in the amount of $93.0 million in exchange for
a 35% ownership interest (15% voting interest) in a newly formed company.
. On November 30, 2000, the Company purchased all outstanding shares of
Florida Progress Corporation (FPC). In conjunction with the purchase of
FPC, the Company issued approximately $1.9 billion in common stock and
approximately $49.3 million in contingent value obligations.
See Notes to consolidated financial statements.
CONSOLIDATED STATEMENTS of CHANGES IN COMMON STOCK EQUTIY
---------------------------------------------------------
Common Stock Outstanding
Unearned Accumulated Total
(In thousands, except share and per share Unearned ESOP Other Common
data) Restricted Common Comprehensive Retained Stock
Shares Amount Stock Stock Income (Loss) Earnings Equity
- -------------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 1999 151,337,503 $1,382,524 ($8,541) ($ 152,979) $ - $ 1,728,301 $2,949,305
Net income 379,288 379,288
Issuance of shares 8,262,147 360,509 360,509
Purchase of restricted stock (2,507) (2,507)
Restricted stock expense
recognition 3,110 3,110
Allocation of ESOP shares 10,360 12,826 23,186
Dividends ($2.015 per share) (300,244) (300,244)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 159,599,650 1,753,393 (7,938) (140,153) - 1,807,345 3,412,647
Net income 478,361 478,361
Issuance of shares 46,527,797 1,863,886 1,863,886
Purchase of restricted stock (10,067) (10,067)
Restricted stock expense
recognition 3,671 3,671
Cancellation of restricted shares (38,400) (1,626) 1,626 -
Allocation of ESOP shares 5,957 12,942 18,899
Dividends ($2.075 per share) (343,196) (343,196)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 206,089,047 3,621,610 (12,708) (127,211) - 1,942,510 5,424,201
Net income 541,610 541,610
FAS 133 transition adjustment
(net of tax of $15,130) (23,567) (23,567)
Change in net unrealized losses
on cash flow hedges
(net of tax of $13,268) (20,703) (20,703)
Foreign currency translation (1,557) (1,557)
Reclassification adjustment for
amounts included in net income
(net of tax of $8,739) 13,647 13,647
----------
Comprehensive income 509,430
----------
Issuance of shares 12,658,027 488,592 488,592
Purchase of restricted stock (7,992) (7,992)
Restricted stock expense
recognition 6,084 6,084
Cancellation of restricted shares (21,722) (915) 915 -
Allocation of ESOP shares 11,907 12,826 24,733
Dividends ($2.135 per share) (441,515) (441,515)
- -------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001 218,725,352 $4,121,194 ($ 13,701) ($ 114,385) ($32,180) $ 2,042,605 $6,003,533
===============================================================================================================================
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
- -------------------------------------------------
(In thousands, except per share data) First Quarter(a) Second Quarter(a) Third Quarter(a) Fourth Quarter(a)
- ---------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues $ 1,908,090 $ 2,315,643(e) $ 2,330,547 $ 1,907,179
Operating income 309,855 284,075 453,518 196,327
Net income 154,003 111,702 366,443 (90,538)(d)
Common stock data:
Basic earnings per common share 0.77 0.56 1.78 (0.43)(d)
Diluted earnings per common share 0.77 0.56 1.77 (0.42)(d)
Dividends paid per common share 0.530 0.530 0.530 0.530
Price per share - high 49.25 45.00 45.79 45.60
low 38.78 40.36 39.25 40.50
- ---------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000
Operating revenues $ 878,618 $ 887,748 $ 1,064,908 $ 1,272,139
Operating income 186,588 209,628 277,300 30,582 (c)
Net income 85,261 107,460 297,083(b) (11,443)(c)
Common stock data:
Basic earnings per common share 0.56 0.70 1.94(b) (0.07)(c)
Diluted earnings per common share 0.56 0.70 1.93(b) (0.07)(c)
Dividends paid per common share 0.515 0.515 0.515 0.515
Price per share - high 37.00 38.00 41.94 49.38
low 28.25 31.00 31.50 38.00
- ---------------------------------------------------------------------------------------------------------------------------
(a) In the opinion of management, all adjustments necessary to
fairly present amounts shown for interim periods have been made.
Results of operations for an interim period may not give a true
indication of results for the year.
(b) Includes gain on sale of BellSouth Carolinas PCS Partnership interest.
(c) Includes approved further accelerated depreciation of $125
million on nuclear generating assets.
(d) Includes impairment and other one-time charges relating to SRS
and Interpath of $152.8 million, after-tax.
(e) Includes seven months of revenue related to Progress Rail
Services due to reversal of Net Assets Held for Sale accounting
treatment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Progress Energy, Inc. (the Company) is a registered holding company under the
Public Utility Holding Company Act (PUHCA) of 1935, as amended. Both the
Company and its subsidiaries are subject to the regulatory provisions of the
PUHCA. The Company was formed as a result of the reorganization of Carolina
Power & Light Company (CP&L) into a holding company structure on June 19, 2000.
All shares of common stock of CP&L were exchanged for an equal number of shares
of the Company. On December 4, 2000, the Company changed its name from CP&L
Energy, Inc. to Progress Energy, Inc. Through its wholly-owned subsidiaries,
CP&L, Florida Power Corporation (Florida Power) and North Carolina Natural Gas
Corporation (NCNG), the Company is primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina, South Carolina and Florida and the transport, distribution and sale
of natural gas in portions of North Carolina. Through the Progress Ventures
business segment, the Company is involved in merchant energy generation, coal
and synthetic fuel operations and energy marketing and trading. Through other
business units, the Company engages in other non-regulated business areas,
including energy management and related services, rail services and
telecommunications.
The Company's results of operations include the results of Florida Progress
Corporation (FPC) for the periods subsequent to November 30, 2000, and of NCNG
for the periods subsequent to July 15, 1999 (See Note 2).
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States and include the
activities of the Company and its majority-owned subsidiaries. Significant
intercompany balances and transactions have been eliminated in consolidation
except as permitted by Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," which provides
that profits on intercompany sales to regulated affiliates are not eliminated
if the sales price is reasonable and the future recovery of the sales price
through the rate making process is probable. The accounting records of CP&L,
Florida Power and NCNG (collectively, "the utilities") are maintained in
accordance with uniform systems of accounts prescribed by the Federal Energy
Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC),
the Public Service Commission of South Carolina (SCPSC) and the Florida Public
Service Commission (FPSC). Certain amounts for 2000 and 1999 have been
reclassified to conform to the 2001 presentation.
Unconsolidated investments in companies over which the Company does not have
control, but have the ability to exercise influence over operating and
financial policies (generally, 20% - 50% ownership) are accounted for under the
equity method of accounting. Other investments are stated principally at cost.
These investments, which total approximately $160 million at December 31, 2001,
are included as miscellaneous property and investments in the Consolidated
Balance Sheets.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with accounting
principles generally accepted in the United States, 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
consolidated financial statements and amounts of revenues and expenses
reflected during the reporting period. Actual results could differ from those
estimates.
D. Inventory
Inventory is carried at average cost. As of December 31, 2001 and 2000,
inventory was comprised of (dollars in thousands):
2001 2000
---------- ------------
Fuel $ 305,858 $ 150,786
Rail equipment and parts 200,697 -
Materials and supplies 354,587 269,546
Other 25,605 653
---------- ------------
Inventory $ 886,747 $ 420,985
========== ============
E. Utility Plant
The cost of additions, including betterments and replacements of units of
property, is charged to utility plant. Maintenance and repairs of property,
and replacements and renewals of items determined to be less than units of
property, are charged to maintenance expense. The cost of units of property
replaced, renewed or retired, plus removal or disposal costs, less salvage, is
charged to accumulated depreciation. Subsequent to the acquisitions of FPC and
NCNG, the utility plants of these entities continue to be presented on a gross
basis to reflect the treatment of such plant in cost-based regulation.
Generally, electric utility plant other than nuclear fuel is pledged as
collateral for the first mortgage bonds of CP&L and Florida Power. Gas utility
plant is not currently pledged as collateral for such bonds.
The balances of utility plant in service at December 31 are listed below (in
thousands), with a range of depreciable lives for each:
2001 2000
----------- -------------
Electric
Production plant (7-33 years) $10,670,717 $ 10,014,635
Transmission plant (30-75 years) 2,013,243 1,964,652
Distribution plant (12-50 years) 5,767,788 5,292,134
General plant and other (8-75 years) 724,273 852,615
----------- -------------
Total electric utility plant 19,176,021 18,124,036
Gas plant (10-40 years) 491,903 378,464
----------- -------------
Utility plant in service $19,667,924 $ 18,502,500
=========== =============
As prescribed in the regulatory uniform systems of accounts, an allowance for
the cost of borrowed and equity funds used to finance utility plant
construction (AFUDC) is charged to the cost of the plant. Regulatory
authorities consider AFUDC an appropriate charge for inclusion in the rates
charged to customers by the utilities over the service life of the property.
The equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. The total equity funds portion
of AFUDC was $10.9 million, $15.5 million and $3.9 million in 2001, 2000 and
1999, respectively. The composite AFUDC rate for CP&L's electric utility plant
was 6.2%, 8.2% and 6.4% in 2001, 2000 and 1999, respectively. The composite
AFUDC rate for Florida Power's electric utility plant was 7.8% in both 2001 and
2000. The composite AFUDC rate for NCNG's gas utility plant was 10.09% in
2001, 2000 and 1999.
F. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2001 2000
---------- ----------
Equipment $ 184,353 $ 109,080
Land and mineral rights 154,728 96,803
Buildings and plants 291,550 231,219
Telecommunications equipment 266,603 192,727
Railcars 56,044 -
Marine equipment 78,868 73,289
Computers, office equipment and software 14,150 23,065
Construction work in progress 342,830 234,689
Accumulated depreciation (316,080) (231,210)
---------- ----------
Diversified business property, net $1,073,046 $ 729,662
========== ==========
Diversified business property is stated at cost. Depreciation is computed on a
straight-line basis using the following estimated useful lives: equipment,
buildings and plants - 3 to 40 years; telecommunications equipment - 5 to 20
years; computers, office equipment and software - 3 to 10 years; railcars - 3
to 20 years; and marine equipment - 3 to 35 years. Depletion of mineral rights
is provided on the units-of-production method based upon the estimates of
recoverable amounts of clean mineral.
G. Depreciation and Amortization
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based on
the estimated remaining useful life of the property, adjusted for estimated net
salvage. Depreciation provisions, including decommissioning costs (See Note
1I) and excluding accelerated cost recovery of nuclear generating assets, as a
percent of average depreciable property other than nuclear fuel, were
approximately 4.0%, 4.1% and 3.9% in 2001, 2000 and 1999, respectively. Total
depreciation provisions were $821.2 million, $721.0 million and $409.6 million
in 2001, 2000 and 1999, respectively.
Depreciation and amortization expense also includes amortization of deferred
operation and maintenance expenses associated with Hurricane Fran, which struck
significant portions of CP&L's service territory in September 1996. In 1996,
the NCUC authorized CP&L to defer these expenses (approximately $40 million)
with amortization over a 40-month period, which expired in December 1999.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost recovery
of its nuclear generating assets beginning January 1, 2000 and continuing
through 2004. Also in 2000, CP&L received approval from the commissions to
further accelerate the cost recovery of its nuclear generation facilities in
2000. The accelerated cost recovery of these assets resulted in additional
depreciation expense of approximately $75 million and $275 million in 2001 and
2000, respectively (See Note 13B). Pursuant to authorizations from the NCUC
and the SCPSC, CP&L accelerated the amortization of certain regulatory assets
over a three-year period beginning January 1997 and expiring December 1999.
The accelerated amortization of these regulatory assets resulted in additional
depreciation and amortization expenses of approximately $68 million in 1999.
Amortization of nuclear fuel costs, including disposal costs associated with
obligations to the U.S. Department of Energy (DOE) and costs associated with
obligations to the DOE for the decommissioning and decontamination of
enrichment facilities, is computed primarily on the unit-of-production method
and charged to fuel expense. The total of these costs for the years ended
December 31, 2001, 2000 and 1999 were $130.1 million, $114.6 million and $110.8
million, respectively.
Goodwill, the excess of purchase price over fair value of net assets of
businesses acquired, is being amortized on a straight-line basis over primarily
40 years. Goodwill amortization expense was $96.8 million, $16.7 million and
$4.0 million in 2001, 2000 and 1999, respectively. Accumulated amortization
was $119.0 million and $24.2 million at December 31, 2001 and 2000,
respectively. Effective January 1, 2002 goodwill will no longer be subject to
amortization over its estimated useful life, but instead, will be subject to an
annual test for impairment (See Note 1L).
H. Diversified Business Expenses
The major components of diversified business expenses for the years ended
December 31, 2001, 2000 and 1999 are as follows (in thousands):
2001 2000 1999
---- ---- ----
Cost of sales $ 1,403,434 $ 80,744 $ 100,776
Depreciation and amortization 86,741 33,139 17,051
General and administrative expenses 279,115 234,132 56,692
Impairment of assets (Note 1J) 44,800 - -
Other 11,230 4,977 70
-----------------------------------------
Diversified business expenses $ 1,825,320 $ 352,992 $ 174,589
=========================================
I. Decommissioning and Dismantlement Provisions
In the Company's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC, the SCPSC and the FPSC and are based on
site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdictions, the
provisions for nuclear decommissioning costs are approved by FERC.
Decommissioning cost provisions, which are included in depreciation and
amortization expense, were $38.5 million, $32.5 million and $33.3 million in
2001, 2000 and 1999, respectively. In January 2002, Florida Power received
regulatory approval from the FPSC to decrease its retail provision for nuclear
decommissioning from approximately $20.5 million annually to approximately $7.7
million annually, effective January 1, 2001.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were approximately $1.0 billion at both December 31, 2001 and
2000. These costs include amounts retained internally and amounts funded in
externally managed decommissioning trusts. Trust earnings increase the trust
balance with a corresponding increase in the accumulated
decommissioning balance. These balances are adjusted for net unrealized gains
and losses related to changes in the fair value of trust assets.
CP&L's most recent site-specific estimates of decommissioning costs were
developed in 1998, using 1998 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring shortly after operating license expiration. These estimates, in 1998
dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million for
Brunswick Unit No. 1, $298.7 million for Brunswick Unit No. 2 and $328.1
million for the Harris Plant. The estimates are 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 estimates exclude the portion attributable to
North Carolina Eastern Municipal Power Agency (Power Agency), which holds an
undivided ownership interest in the Brunswick and Harris nuclear generating
facilities. Operating licenses for CP&L's nuclear units expire in the year 2010
for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit
No. 2 and 2026 for the Harris Plant.
Florida Power's most recent site-specific estimate of decommissioning
costs for the Crystal River Nuclear Plant (CR3) was developed in 2000 based on
prompt dismantlement decommissioning. The estimate, in 2000 dollars, was $490.9
million and is subject to change based on the same factors as discussed above
for CP&L's estimates. The cost estimate excludes the portion attributable to
other co-owners of CR3. CR3's operating license expires in 2016.
Management believes that the decommissioning costs being recovered through
rates by CP&L and Florida Power, when coupled with reasonable assumed after-tax
fund earnings rates, are currently sufficient to provide for the costs of
decommissioning.
Florida Power maintains a reserve for fossil plant dismantlement. At December
31, 2001 and 2000, this reserve was approximately $140.5 million and $134.6
million, respectively, and was included in accumulated depreciation. The
provision for fossil plant dismantlement was previously suspended per a 1997
FPSC settlement agreement, but resumed mid-2001. The current annual provision,
approved by the FPSC, is $8.8 million.
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" that will impact the accounting
for decommissioning and dismantlement provisions (See Note 1L).
J. Impairment of Long-lived Assets and Investments
SFAS No. 121 "Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to Be Disposed Of" requires review of long-lived assets and
certain intangibles for impairment when events or circumstances indicate that
the carrying value of an asset may not be recoverable. Any impairment losses
are reported in the period in which the recognition criteria are first applied
based on the fair value of the asset. Due to historical and current year losses
at Strategic Resource Solutions Corp. (SRS) and the decline in the market value
for technology companies, the Company has evaluated the long-lived assets of
SRS. Fair value was generally determined based on discounted cash flows. As a
result of this review, the Company recorded asset impairments, primarily
goodwill, and other one-time charges totaling $44.8 million on a pre-tax basis
during the fourth quarter of 2001 related to SRS. Asset write-downs resulting
from this review were charged to diversified business expenses on the
Consolidated Statements of Income.
The Company continually reviews its investments to determine whether a decline
in fair value below the cost basis is other-than-temporary. Effective June 28,
2000, a subsidiary of the Company contributed the net assets used in its
application service provider business to a newly formed company (Interpath) for
a 35% ownership interest (15% voting interest). The Company obtained a
valuation study to assess its investment in Interpath based on current
valuations in the technology sector. As a result, the Company has recorded
investment impairments for other-than-temporary declines in the fair value of
its investment in Interpath. Investment impairments were also recorded related
to certain investments of SRS. Investment write-downs totaled $164.2 million on
a pre-tax basis for the year ended December 31, 2001.
K. Other Policies
The Company recognizes electric utility revenues as service is rendered to
customers. Operating revenues include unbilled electric utility revenues earned
when service has been delivered but not billed by the end of the accounting
period. Diversified business revenues are generally recognized at the time
products are shipped or as services are rendered. Leasing activities are
accounted for in accordance with SFAS No. 13, "Accounting for Leases."
Fuel expense includes fuel costs or recoveries that are deferred through fuel
clauses established by the electric utilities' regulators. These clauses allow
the utilities' to recover fuel costs and portions of purchased power costs
through surcharges on customer rates. NCNG is also allowed to recover the costs
of gas purchased for resale through customer rates.
Operations of Progress Rail Services Corporation and certain other diversified
operations are recognized one-month in arrears.
The Company maintains an allowance for doubtful accounts receivable, which
totaled approximately $40.7 million and $28.1 million at December 31, 2001 and
2000, respectively. Long-term debt premiums, discounts and issuance expenses
for the utilities are amortized over the life of the related debt using the
straight-line method. Any expenses or call premiums associated with the
reacquisition of debt obligations by the utilities are amortized over the
remaining life of the original debt using the straight-line method. The Company
considers all highly liquid investments with original maturities of three
months or less to be cash equivalents.
L. Impact of New Accounting Standards
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138.
SFAS No. 133, as amended, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS No. 133 requires that an
entity recognize all derivatives as assets or liabilities in the consolidated
balance sheet and measure those instruments at fair value.
As a result of the adoption of SFAS No. 133, the Company recorded a transition
adjustment as a cumulative effect of a change in accounting principle of $23.6
million, net of tax, which increased accumulated other comprehensive loss as of
January 1, 2001. This amount relates to several derivatives used to hedge cash
flows related to interest on long-term debt (See Note 14). The net derivative
losses will be reclassified into earnings consistent with hedge designations,
primarily over the life of the related debt instruments, which principally
range from three to ten years. The Company estimates that approximately $15.5
million of the net losses at December 31, 2001 will be reclassified into
earnings during 2002. There was no transition adjustment affecting the
consolidated statement of income as a result of the adoption of SFAS No. 133.
During the second quarter of 2001, the FASB issued interpretations of SFAS No.
133 indicating that options in general cannot qualify for the normal purchases
and sales exception, but provided an exception that allows certain electricity
contracts, including certain capacity-energy contracts, to be excluded from the
mark-to-market requirements of SFAS No. 133. The interpretations were effective
July 1, 2001. Those interpretations did not require the Company to
mark-to-market any of its electricity capacity-energy contracts currently
outstanding. In December 2001, the FASB revised the criteria related to the
exception for certain electricity contracts, with the revision to be effective
April 1, 2002. The Company does not expect the revised interpretation to change
its assessment of mark-to-market requirements for its current contracts. If an
electricity or fuel supply contract in its regulated businesses is subject to
mark-to-market accounting, there would be no income statement effect of the
mark-to-market because the contract's mark-to-market gain or loss will be
recorded as a regulatory asset or liability. Any mark-to-market gains or losses
in its non-regulated businesses will affect income unless those contracts
qualify for hedge accounting treatment.
The application of the new rules is still evolving, and further guidance from
the FASB is expected, which could additionally impact the Company's financial
statements.
Effective January 1, 2002, the Company adopted SFAS No. 141, "Business
Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." These
statements require that all business combinations initiated after June 30, 2001
be accounted for using the purchase method of accounting and clarifies the
criteria for recording of other intangible assets separately from goodwill.
Effective January 1, 2002, goodwill is no longer subject to amortization over
its estimated useful life. Instead, goodwill is subject to at least an annual
assessment for impairment by applying a fair-value based test. This assessment
could result in periodic impairment charges. The Company has not yet determined
whether its goodwill is impaired under the initial impairment test required.
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" in
July 2001. This statement provides accounting requirements for retirement
obligations associated with tangible long-lived assets and is effective January
1, 2003. This statement requires that the present value of retirement costs for
which the Company has a legal obligation be recorded as liabilities with an
equivalent amount added to the asset cost and depreciated over an appropriate
period. The Company is currently assessing the effects this statement may
ultimately have on the Company's accounting for decommissioning, dismantlement
and other retirement costs.
Effective January 1, 2002, the Company adopted SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
It also supersedes the accounting and reporting provisions of Accounting
Principles Board (APB) Opinion No. 30, "Reporting the Results of Operations -
Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions"
related to the disposal of a segment of a business. Adoption of this
statement did not have a material effect on the Company's financial
statements.
2. Acquisitions and Dispositions
A. Florida Progress Corporation
On November 30, 2000, the Company completed its acquisition of FPC for an
aggregate purchase price of approximately $5.4 billion. The Company paid cash
consideration of approximately $3.5 billion and issued 46.5 million common
shares valued at approximately $1.9 billion. In addition, the Company issued
98.6 million contingent value obligations (CVO) valued at approximately $49.3
million (See Note 8). The purchase price includes $20.1 million in direct
transaction costs.
FPC is a diversified, exempt electric utility holding company. Florida Power,
FPC's largest subsidiary, is a regulated public utility engaged in the
generation, transmission, distribution and sale of electricity. FPC also has
diversified non-utility operations owned through Progress Capital Holdings,
Inc. Included in diversified operations are Progress Fuels Corporation, an
energy and transportation company, and Progress Telecommunications
Corporation, a wholesale telecommunications service provider. As of the
acquisition date, the primary segments of Progress Fuels were energy and
related services, rail services, and inland marine transportation.
The acquisition was accounted for using the purchase method of accounting
and, accordingly, the results of operations for FPC have been included in the
Company's consolidated financial statements since the date of acquisition.
Identifiable assets acquired and liabilities assumed have been recorded at
their fair values of $6.7 billion and $4.9 billion, respectively. The excess
of the purchase price over the fair value of the net identifiable assets and
liabilities acquired has been recorded as goodwill. The goodwill, of
approximately $3.6 billion, was being amortized on a straight-line basis over
a period of 40 years. Effective January 1, 2002, goodwill is no longer
subject to amortization (See Note 1L).
The fair values of FPC's rate-regulated net assets acquired were considered
to be equivalent to book value since book value represents the amount that
will be recoverable through regulated rates. Initially, the allocation of the
purchase price included estimated amounts expected to be realized from the
sale of FPC's Rail Services ("Rail Services") and Inland Marine
Transportation business segments which were classified as net assets held for
sale. During 2001, the Company announced its intention to retain the Rail
Services segment within the allocation period and, therefore, these assets
were reclassified to operating assets. Accordingly, the Company has made
adjustments to the purchase price allocation to remove Rail Services from net
assets held for sale and reflect the net realizable value from the
disposition of FPC's Inland Marine Transportation business segment (See Note
4). A Securities and Exchange Commission order approving the merger requires
the Company to divest of Rail Services and certain immaterial, non-regulated
investments of FPC by November 30, 2003.
The company made adjustments during 2001 to the purchase price allocation for
changes in preliminary assumptions and analyses, based on receipt of the
following additional information:
. final actuarial valuations of pension plan obligations
. proceeds realized from the disposition of assets held for sale
. valuations of non-regulated businesses and individual assets and
liabilities
The original allocation of purchase price included the assumption of
liabilities associated with change in control payments triggered by the
acquisition and executive termination benefits, totaling approximately $50.8
million. Substantially all change in control and executive termination
payments were paid as of December 31, 2000. During 2000, the Company began
the implementation of a plan to combine operations of the companies resulting
in an original non-executive involuntary termination cost accrual of
approximately $52.2 million. Approximately $41.8 million was attributable to
Florida Power employees and was reflected as part of the purchase price
allocation, while approximately $10.4 million attributable to the acquiring
company's employees was charged to operating results in 2000. During 2001,
the Company finalized the plan to combine operations of the companies with
final termination payments occurring in 2002.
The activity for the non-executive involuntary termination costs is detailed
in the table below:
(in millions) 2001
------
Balance at January 1 $ 52.2
Payments (33.1)
Adjustments credited to operating results (4.8)
Adjustments credited to purchase price allocation (6.1)
------
Balance at December 31 $ 8.2
======
Actuarial valuations resulted in adjustments to increase the other
postretirement benefits liability by $16.8 million and the prepaid pension
asset by $283.4 million. These adjustments were substantially offset by the
establishment of a regulatory asset for other postretirement benefits of
approximately $15.9 million and a pension regulatory liability of $258.4
million. In addition, an adjustment increased the supplementary defined
benefit retirement plan liability by $24.4 million.
The following unaudited pro forma combined results of operations have been
prepared assuming the acquisition of FPC had occurred at the beginning of
each period. The pro forma results are provided for information only. The pro
forma results include the effect of 2001 purchase price allocation
adjustments and, therefore, differ from previously reported pro forma results
for the same periods. The results are not necessarily indicative of the
actual results that would have been realized had the acquisition occurred on
the indicated date, nor are they necessarily indicative of future results of
operations of the combined companies.
(in thousands, except per share data) 2000 1999
---- ----
Revenues $ 8,098,356 $ 7,083,641
Net income 575,112 451,455
Basic earnings per share 2.88 2.32
Diluted earnings per share 2.87 2.32
Average shares - Basic 199,722 194,591
Average shares - Diluted 200,177 194,966
B. North Carolina Natural Gas Corporation
On July 15, 1999, the Company completed the acquisition of NCNG for an
aggregate purchase price of approximately $364 million, resulting in the
issuance of approximately 8.3 million shares. The acquisition was accounted
for as a purchase and, accordingly, the operating results of NCNG were
included in the Company's consolidated financial statements beginning with
the date of acquisition. The excess of the aggregate purchase price over the
fair value of net assets acquired, approximately $240 million, was recorded
as goodwill of the acquired business and is being amortized primarily over a
period of 40 years. Effective January 1, 2002, goodwill will no longer be
subject to amortization (See Note 1L).
C. BellSouth Carolinas PCS Partnership Interest
In September 2000, Caronet, Inc., a wholly-owned subsidiary of CP&L, sold its
10% limited partnership interest in BellSouth Carolinas PCS for $200 million.
The sale resulted in an after-tax gain of $121.1 million.
3. Financial Information by Business Segment
The Company currently provides services through the following business
segments: CP&L Electric, Florida Power Electric, Progress Ventures, Rail
Services and Other. Prior periods have been restated to reflect the current
operating segments.
FPC's operations are not included in the Company's results of operations
prior to the acquisition date of November 30, 2000.
The CP&L Electric and Florida Power Electric segments are engaged in the
generation, transmission, distribution, and sale of electric energy in
portions of North Carolina, South Carolina and Florida. Electric operations
are subject to the rules and regulations of FERC, the NCUC, the SCPSC and the
FPSC.
The Progress Ventures segment is primarily engaged in merchant energy
generation and coal and synthetic fuel operations. Management reviews the
operations of this segment after allocating energy marketing and trading
activity to Progress Ventures. The energy marketing and trading activity is
currently performed by Progress Ventures on behalf of the regulated
utilities, CP&L and Florida Power, and includes wholesale sales on behalf of
these utilities. Electric wholesale operations are subject to the rules and
regulations of FERC, the NCUC, the SCPSC and the FPSC.
The Rail Services segment operations include railcar repair, rail parts
reconditioning and sales, railcar leasing and sales, providing rail and track
material, and scrap metal recycling.
The Other segment is primarily made up of natural gas, other diversified
businesses and holding company operations, which includes the transportation,
distribution and sale of natural gas in portions of North Carolina,
telecommunication services, energy management services, miscellaneous
non-regulated activities and elimination entries.
For reportable segments presented in the accompanying table, segment income
includes intersegment revenues accounted for at prices representative of
unaffiliated party transactions. Intersegment revenues that are not
eliminated represent natural gas sales to the CP&L Electric and the Florida
Power Electric segments.
Florida
CP&L Power Progress Rail Consolidated
(In thousands) Electric Electric Ventures Services(b) Other Totals
------------------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED 12/31/01
<c> <c>
Revenues
Unaffiliated $ 3,343,720 $3,212,841 $ 526,200 $ 944,985 $ 415,063 $ 8,442,809
Intersegment - - 398,228 1,174 (380,752) 18,650
------------------------------------------------------------------------------------
Total Revenues 3,343,720 3,212,841 924,428 946,159 34,311 8,461,459
Depreciation and Amortization 521,910 452,971 40,695 36,053 125,290 1,176,919
Net Interest Charges 241,427 113,707 24,085 40,589 265,005 684,813
Income Taxes 264,078 182,590 (421,559) (6,416) (170,336) (151,643)
Net Income (Loss) 468,328 309,577 201,989 (12,108) (426,176) 541,610
Segment Income (Loss) After Allocation(a) 405,661 285,566 288,667 (12,108) (426,176) 541,610
Total Segment Assets 8,918,691 4,998,162 1,018,875 602,597 5,201,466 20,739,791
Capital and Investment Expenditures 823,952 323,170 265,183 12,886 141,070 1,566,261
==============================================================================================================================
FOR THE YEAR ENDED 12/31/00
Revenues
Unaffiliated $ 3,308,215 $ 241,606 $ 108,739 $ - $ 438,956 $ 4,097,516
Intersegment - - 15,717 - (9,820) 5,897
------------------------------------------------------------------------------------
Total Revenues 3,308,215 241,606 124,456 - 429,136 4,103,413
Depreciation and Amortization 698,633 28,872 17,020 - 43,362 787,887
Net Interest Charges 221,856 9,777 5,714 - 24,938 262,285
Income Taxes 227,705 13,580 (109,057) - 70,546 202,774
Net Income 373,764 21,764 39,816 - 43,017 478,361
Segment Income After Allocation(a) 289,724 20,057 125,563 - 43,017 478,361
Total Segment Assets 8,839,720 4,997,728 644,234 - 5,629,019 20,110,701
Capital and Investment Expenditures 805,489 49,805 38,981 - 302,902 1,197,177
==============================================================================================================================
------------------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED 12/31/99
Revenues
Unaffiliated $ 3,146,158 $ - $225 $ - $ 217,527 $ 3,363,910
Intersegment - - - - 1,017 1,017
------------------------------------------------------------------------------------
Total Revenues 3,146,158 - 225 - 218,544 3,364,927
Depreciation and Amortization 493,938 - 93 - 26,125 520,156
Net Interest Charges 183,099 - - - (3,635) 179,464
Income Taxes 275,769 - 38 - (17,386) 258,421
Net Income (Loss) 430,295 - 56 - (51,063) 379,288
Segment Income (Loss) After Allocation(a) 360,821 - 69,530 - (51,063) 379,288
Total Segment Assets 8,501,273 - 98,429 - 894,317 9,494,019
Capital and Investment Expenditures 671,401 - 90,678 - 133,042 895,121
==============================================================================================================================
(a) Includes allocation of energy trading and marketing net income managed by
Progress Ventures on behalf of the electric utilities.
(b) Amounts for the year ended December 31, 2001 reflect cumulative operating
results of Rail Services since the acquisition date of November 30, 2000. As
of December 31, 2000, the Rail Services segment was included as Net Assets
Held for Sale; and therefore, no assets are reflected for this segment as of
that date.
Segment totals for depreciation and amortization expense include expenses
related to the Progress Ventures, Rail Services and the other segment that
are included in diversified business expenses on the Consolidated Statements
of Income. Segment totals for interest expense exclude immaterial expenses
related to the Progress Ventures, Rail Services and the other segment that
are included in other, net on the Consolidated Statements of Income.
4. Net Assets Held for Sale
The estimated amounts reported for the expected sale of FPC's Rail Services
("Rail Services") and Inland Marine Transportation business segments, $679.1
million and $68.6 million, respectively, were classified as net assets held
for sale as of December 31, 2000. During 2001, the Company announced its
intention to retain the Rail Services segment within the allocation period
and, therefore, reclassified Rail Services to operating assets. During 2001,
the Company recorded an after-tax charge of $3.2 million reflecting the
reversal of net assets held for sale accounting.
During 2001, the Company completed the sale of the Inland Marine
Transportation segment and related investments to AEP Resources, Inc., a
wholly-owned subsidiary of American Electric Power, for a sales price of $270
million. Of the $270 million purchase price, $230 million was used to pay
early termination of certain off-balance sheet arrangements for assets leased
by the business segment. In connection with the sale, the Company entered
into environmental indemnification provisions covering both known and unknown
sites (see Note 20D).
The Company adjusted the FPC purchase price allocation to reflect a $15.0
million negative net realizable value of the Inland Marine business segment
(see Note 2A). The Company's results of operations exclude Inland Marine
Transportation segment net income of $9.1 million for 2001 and $1.8 million
for the month of December 2000. These earnings were included in the
determination of net realizable value for purchase price allocation. As a
result of the change in net realizable value, the Company recorded interest
expense in 2001, net of tax, of $0.3 million to reverse the interest
allocated during 2000.
5. Related Party Transactions
Prior to the acquisition of FPC, the Company purchased a 90% membership
interest in two synthetic fuel related limited liability companies from a
wholly-owned subsidiary of FPC. Interest expense incurred during the
pre-acquisition period was approximately $3.3 million. Subsequent to the
acquisition date, intercompany amounts have been eliminated in consolidation.
NCNG sells natural gas to both CP&L and Florida Power. For the years ended
December 31, 2001, 2000 and 1999, sales of natural gas to CP&L and Florida
Power that were not eliminated in consolidation were $18.7 million, $5.9
million and $1.0 million, respectively.
The Company and its subsidiaries have guarantees, surety bonds and stand by
letters of credit of approximately $140.0 million at December 31, 2001
relating to prompt performance payments, lease obligations, self-insurance
and other payments subject to certain contingencies. As of December 31, 2001,
management does not believe conditions are likely for performance under these
agreements.
6. Debt and Credit Facilities
At December 31, 2001 and 2000 the Company's long-term debt consisted of the
following (maturities and weighted-average interest rates as of December 31,
2001):
(in thousands) 2001 2000
-------------------------
Progress Energy, Inc.:
Senior unsecured notes, maturing 2004-2031 6.93% $ 4,000,000 -
Commercial paper reclassified to long-term debt 3.02% 450,000 -
Unamortized premium and discount, net (29,708) -
-------------------------
4,420,292 -
-------------------------
Carolina Power and Light Company:
First mortgage bonds, maturing 2003-2023 7.02% 1,800,000 1,800,000
Pollution control obligations, maturing 2009-2024 2.22% 707,800 713,770
Unsecured subordinated debentures, maturing 2025 - 125,000
Extendible notes, maturing 2002 2.83% 500,000 500,000
Medium-term notes, maturing 2008 6.65% 300,000 -
Commercial paper reclassified to long-term debt 3.10% 260,535 486,297
Miscellaneous notes 6.43% 7,234 8,360
Unamortized premium and discount, net (16,716) (12,407)
-------------------------
3,558,853 3,621,020
-------------------------
Florida Power Corporation:
First mortgage bonds, maturing 2003-2023 6.83% 810,000 510,000
Pollution control revenue bonds, maturing 2014-2027 6.59% 240,865 240,865
Medium-term notes, maturing 2002-2028 6.73% 449,100 531,100
Commercial paper reclassified to long-term debt 2.54% 154,250 200,000
Unamortized premium and discount, net (2,935) (2,849)
-------------------------
1,651,280 1,479,116
-------------------------
Florida Progress Funding Corporation (Note 7):
Mandatorily redeemable preferred securities, maturing 2039 7.10% 300,000 300,000
Purchase accounting fair value adjustment (30,413) -
Unamortized premium and discount, net (8,922) -
-------------------------
260,665 300,000
-------------------------
Progress Capital Holdings:
Medium-term notes, maturing 2002-2008 6.74% 273,000 374,000
Commercial paper reclassified to long-term debt - 300,000
Miscellaneous notes 7,707 -
-------------------------
280,707 674,000
-------------------------
Current portion of long-term debt (688,052) (184,037)
-------------------------
Total Long-Term Debt, Net $ 9,483,745 $5,890,099
=========================
At December 31, 2001, the Company had committed lines of credit totaling
$1.945 billion, all of which are used to support its commercial paper
borrowings. The Company is required to pay minimal annual commitment fees to
maintain its credit facilities. The following table summarizes the Company's
credit facilities:
Subsidiary Description Short-term Long-term Total
----------------------------------------------------------------------------------------
Progress Energy 364-Day $ 550 $ - $ 550
Progress Energy 3-Year (3 years remaining) - 450 450
CP&L 364-Day - 200 200
CP&L 5-Year (2 years remaining) - 375 375
Florida Power 364-Day 170 - 170
Florida Power 5-Year (2 years remaining) - 200 200
--------------------------------------
$ 720 $ 1,225 $ 1,945
======================================
As of December 31, 2001, there were no loans outstanding under these
facilities. CP&L's 364-day revolving credit agreement is considered a
long-term commitment due to an option to convert to a one-year term loan at
the expiration date.
Based on the available balances on the long-term facilities, commercial paper
of approximately $865 million has been reclassified to long-term debt at
December 31, 2001. Commercial paper of approximately $986 million was
reclassified to long-term debt at December 31, 2000. As of December 31, 2001
and 2000, the Company had an additional $78 million and $4 billion,
respectively of outstanding commercial paper and other short-term debt
classified as short-term obligations. The weighted-average interest rates of
such short-term obligations at December 31, 2001 and 2000 were 2.95% and
7.40%, respectively.
Florida Power and Progress Capital Holdings, Inc. (Progress Capital),
subsidiaries of FPC, have two uncommitted bank bid facilities authorizing
them to borrow and re-borrow, and have loans outstanding at any time, up to
$100 million and $300 million, respectively. These bank bid facilities were
not drawn as of December 31, 2001.
The combined aggregate maturities of long-term debt for 2002 through 2006 are
approximately $688 million, $698 million, $1.3 billion, $348 million, and
$909 million, respectively.
7. FPC-Obligated Mandatorily Redeemable Preferred Securities (QUIPS) of a
Subsidiary Holding Solely FPC Guaranteed Notes
In April 1999, FPC Capital I (the Trust), an indirect wholly-owned subsidiary
of FPC, issued 12 million shares of $25 par cumulative FPC-obligated
mandatorily redeemable preferred securities (Preferred Securities) due 2039,
with an aggregate liquidation value of $300 million and a quarterly
distribution rate of 7.10%. Currently, all 12 million shares of the Preferred
Securities that were issued are outstanding. Concurrent with the issuance of
the Preferred Securities, the Trust issued to Florida Progress Funding
Corporation (Funding Corp.) all of the common securities of the Trust
(371,135 shares) for $9.3 million. Funding Corp. is a direct wholly owned
subsidiary of FPC.
The preferred securities are included in long-term debt on the Consolidated
Balance Sheets (See Note 6). During 2001, an adjustment was recorded to the
book value of the preferred securities resulting from fair value adjustments
recorded under the purchase method of accounting. The fair value adjustment
decreased the carrying value of these securities by $30.5 million.
The existence of the Trust is for the sole purpose of issuing the Preferred
Securities and the common securities and using the proceeds thereof to
purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable Interest
Notes (subordinated notes) due 2039, for a principal amount of $309.3
million. The subordinated notes and the Notes Guarantee (as discussed below)
are the sole assets of the Trust. Funding Corp.'s proceeds from the sale of
the subordinated notes were advanced to Progress Capital and used for general
corporate purposes including the repayment of a portion of certain
outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding Corp.
under the subordinated notes (the Notes Guarantee). In addition, FPC has
guaranteed the payment of all distributions required to be made by the Trust,
but only to the extent that the Trust has funds available for such
distributions (Preferred Securities Guarantee). The Preferred Securities
Guarantee, considered together with the Notes Guarantee, constitutes a full
and unconditional guarantee by FPC of the Trust's obligations under the
Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp.
beginning in 2004 at par value plus accrued interest through the redemption
date. The proceeds of any redemption of the subordinated notes will be used
by the Trust to redeem proportional amounts of the Preferred Securities and
common securities in accordance with their terms. Upon liquidation or
dissolution of Funding Corp., holders of the Preferred Securities would be
entitled to the liquidation preference of $25 per share plus all accrued and
unpaid dividends thereon to the date of payment.
8. Contingent Value Obligations
In connection with the acquisition of FPC during 2000, the Company issued
98.6 million CVOs. Each CVO represents the right to receive contingent
payments based on the performance of four synthetic fuel facilities purchased
by subsidiaries of FPC in October 1999. The payments, if any, would be based
on the net after-tax cash flows the facilities generate. The initial
liability recorded at the acquisition date was approximately $49.3 million.
The CVO liability is adjusted to reflect market price fluctuations. The
liability, included in other liabilities and deferred credits, at December
31, 2001 and 2000, was $41.9 million and $40.4 million, respectively.
9. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption
All of the Company's preferred stock at December 31, 2001 and 2000 was issued
by its subsidiaries and was not subject to mandatory redemption. Preferred
stock outstanding of subsidiaries consisted of the following:
2001 2000
-------------------
CP&L:
Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock;
20,000,000 shares, cumulative, $100 par value Serial Preferred Stock
$5.00 Preferred - 236,997 shares outstanding (redemption price $110.00) $24,349 $24,349
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000 10,000
$5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00) 24,985 24,985
-------------------
$59,334 $59,334
-------------------
Florida Power:
Authorized - 4,000,000 shares, cumulative, $100 par value Preferred Stock;
5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000 shares,
$100 par value Preference Stock
$100 par value Preferred Stock:
4.00% - 39,980 shares outstanding (redemption price $104.25) $ 3,998 $ 3,998
4.40% - 75,000 shares outstanding (redemption price $102.00) 7,500 7,500
4.58% - 99,990 shares outstanding (redemption price $101.00) 9,999 9,999
4.60% - 39,997 shares outstanding (redemption price $103.25) 4,000 4,000
4.75% - 80,000 shares outstanding (redemption price $102.00) 8,000 8,000
-------------------
33,497 33,497
-------------------
Total Preferred Stock of Subsidiaries $92,831 $92,831
===================
10. Leases
The Company leases office buildings, computer equipment, vehicles, railcars
and other property and equipment with various terms and expiration dates.
Some rental payments for transportation equipment include minimum rentals
plus contingent rentals based on mileage. Contingent rentals are not
significant. Rent expense (under operating leases) totaled $62.6 million,
$26.8 million and $21.3 million for 2001, 2000 and 1999, respectively.
Assets recorded under capital leases at December 31 consist of (in
thousands):
2001 2000
---- ----
Buildings $ 27,626 $27,626
Equipment 12,170 9,366
Less: Accumulated amortization (8,975) (8,018)
-------- -------
$ 30,821 $28,974
======== =======
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as of
December 31, 2001 are (in thousands):
Capital Leases Operating Leases
-------------- ----------------
2002 $ 3,533 $ 52,339
2003 3,533 66,317
2004 3,533 50,245
2005 3,533 30,278
2006 3,459 22,132
Thereafter 35,675 86,265
----------- -------------
$ 53,266 $ 307,576
Less amount representing imputed interest (22,445) =============
Present value of net minimum lease payments -----------
under capital leases $ 30,821
===========
The Company is also a lessor of land, buildings, railcars and other types of
properties it owns under operating leases with various terms and expiration
dates. The leased buildings and railcars are depreciated under the same terms
as other buildings and railcars included in diversified business property.
Minimum rentals receivable under noncancelable leases as of December 31,
2001, are (in thousands):
Amounts
-------
2002 $12,190
2003 7,904
2004 5,591
2005 4,741
2006 3,766
Thereafter 9,222
-------
$43,414
=======
11. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term obligations
approximate fair value due to the short maturities of these instruments. At
December 31, 2001 and 2000, there were miscellaneous investments, consisting
primarily of investments in company-owned life insurance, with carrying
amounts of approximately $124.3 million and $187.8 million, respectively,
included in miscellaneous other property and investments. The carrying amount
of these investments approximates fair value due to the short maturity of
certain instruments and certain instruments are presented at fair value. The
carrying amount of the Company's long-term debt, including current
maturities, was $10.2 billion and $6.1 billion at December 31, 2001 and 2000,
respectively. The estimated fair value of this debt, as obtained from quoted
market prices for the same or similar issues, was $10.6 billion and $6.0
billion at December 31, 2001 and 2000, respectively.
External funds have been established as a mechanism to fund certain costs of
nuclear decommissioning (See Note 1I). These nuclear decommissioning trust
funds are invested in stocks, bonds and cash equivalents. Nuclear
decommissioning trust funds
are presented on the Consolidated Balance Sheet at amounts that approximate
fair value. Fair value is obtained from quoted market prices for the same or
similar investments.
12. Common Stock
In August 2001, the Company issued 12.65 million shares of common stock at
$40 per share for net cash proceeds of $488 million. Proceeds from the
issuance were primarily used to retire commercial paper. During 2000 and
1999, the Company issued common stock in conjunction with the FPC and NCNG
acquisitions, respectively (See Note 2).
As of December 31, 2001, the Company had 38,549,922 shares of common stock
authorized by the board of directors that remained unissued and reserved,
primarily to satisfy the requirements of the Company's stock plans. The
Company intends, however, to meet the requirements of these stock plans with
issued and outstanding shares presently held by the Trustee of the Progress
Energy 401(k) Savings and Stock Ownership Plan (previously known as the Stock
Purchase-Savings Plan) or with open market purchases of common stock shares,
as appropriate.
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2001,
there were no significant restrictions on the use of retained earnings.
13. Regulatory Matters
A. Regulatory Assets and Liabilities
As regulated entities, the utilities are subject to the provisions of SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, the utilities record certain assets and liabilities resulting
from the effects of the ratemaking process, which would not be recorded under
generally accepted accounting principles for non-regulated entities. The
utilities' ability to continue to meet the criteria for application of SFAS
No. 71 may be affected in the future by competitive forces and restructuring
in the electric utility industry. In the event that SFAS No. 71 no longer
applied to a separable portion of the Company's operations, related
regulatory assets and liabilities would be eliminated unless an appropriate
regulatory recovery mechanism is provided. Additionally, these factors could
result in an impairment of utility plant assets as determined pursuant to
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (See Note 1J).
At December 31, 2001 and 2000, the balances of the utilities' regulatory
assets (liabilities) were as follows (in thousands):
2001 2000
---- ----
Deferred fuel (included in current assets) $ 146,652 $ 217,806
---------------------------
Income taxes recoverable through future rates 234,180 228,686
Deferred purchased power contract termination costs 95,326 226,656
Harris Plant deferred costs 32,476 44,813
Loss on reacquired debt 28,931 28,121
Deferred DOE enrichment facilities-related costs 39,102 46,006
Other postretirement benefits 12,207 15,670
Other 13,103 23,248
---------------------------
Total long-term regulatory assets 455,325 613,200
---------------------------
Nuclear maintenance and refueling (346) (10,835)
Defined benefit retirement plan (234,102) (203,137)
Deferred revenues - (63,000)
Emission allowance gains (7,494) -
Storm reserve (35,527) (29,527)
Other (9,669) (10,077)
---------------------------
Total long-term regulatory liabilities (287,138) (316,576)
---------------------------
Net regulatory assets $ 314,839 $ 514,430
===========================
Except for portions of deferred fuel, all assets earn a return or the cash
has not yet been expended, in which case, the assets are offset by
liabilities that do not incur a carrying cost.
B. Retail Rate Matters
The NCUC and SCPSC approved proposals to accelerate cost recovery of CP&L's
nuclear generating assets beginning January 1, 2000, and continuing through
2004. The accelerated cost recovery began immediately after the 1999
expiration of the accelerated amortization of certain regulatory assets (See
Note 1G). Pursuant to the orders, the accelerated depreciation expense for
nuclear generating assets was set at a minimum of $106 million with a maximum
of $150 million per year. In late 2000, CP&L received approval from the NCUC
and the SCPSC to further accelerate the cost recovery of its nuclear
generation facilities by $125 million in 2000. This additional depreciation
allowed CP&L to reduce the minimum accelerated annual depreciation in 2001
through 2004 to $75 million. The resulting total accelerated depreciation was
$75 million in 2001 and $275 million in 2000. Recovering the costs of its
nuclear generating assets on an accelerated basis will better position CP&L
for the uncertainties associated with potential restructuring of the electric
utility industry.
In compliance with a regulatory order, Florida Power accrues a reserve for
maintenance and refueling expenses anticipated to be incurred during
scheduled nuclear plant outages.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion
of its annual accelerated cost recovery of nuclear generating assets by the
amount of sulfur dioxide (SO2) emission allowance expense. CP&L did not
offset accelerated depreciation expense in 2001 against emission allowance
expense. CP&L is allowed to recover emission allowance expense through the
fuel clause adjustment in its South Carolina retail jurisdiction. Florida
Power is also allowed to recover its emission allowance expenses through the
fuel adjustment clause in its retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004.
The cap on base retail electric rates in South Carolina was extended to
December 2005 in conjunction with regulatory approval to form a holding
company. NCNG also agreed to cap its North Carolina margin rates for gas
sales and transportation services, with limited exceptions, through November
1, 2003. In February 2002, NCNG filed a general rate case with the NCUC
requesting an annual rate increase of $47.6 million, based upon its
completion of major expansion projects. The Company cannot predict the final
outcome of this matter.
In conjunction with the FPC merger, CP&L reached a settlement with the Public
Staff of the NCUC in which it agreed to reduce rates to all of its non-real
time pricing customers by $3 million in 2002, $4.5 million in 2003, $6
million in 2004 and $6 million in 2005. CP&L also agreed to write off and
forego recovery of $10 million of unrecovered fuel costs in each of its 2000
NCUC and SCPSC fuel cost recovery proceedings.
At December 31, 2000, Florida Power, with the approval of the FPSC, had
established a regulatory liability to defer $63 million of revenues. In 2001,
Florida Power applied the deferred revenues, plus accrued interest, to offset
its regulatory asset related to deferred purchased power termination costs.
In addition, Florida Power recorded accelerated amortization of $34.0 million
to further offset this regulatory asset during 2001.
Florida Power previously operated under an agreement committing several
parties not to seek any reduction in its base rates or authorized return on
equity. During 2001, the FPSC required Florida Power to submit minimum filing
requirements, based on a 2002 projected test year, to initiate a rate
proceeding regarding its future base rates. The FPSC required that annual
revenues of $98 million be held subject to refund to its customers. The FPSC
may allow Florida Power to reduce the amount subject to refund if it is
successful in recovering certain expenses incurred during 2001.
On September 14, 2001, Florida Power submitted its required rate filing,
including its revenue requirements and supporting testimony. Under the
filing, Florida Power customers would receive a $5 million annual credit rate
for 15 years, or $75 million in total, from net synergies of its merger with
the Company. Additionally, the filing provides that the regulatory asset
(approximately $95 million at December 31, 2001) related to the purchase of
Tiger Bay cogeneration facility in 1997 would be fully amortized by the end
of 2003, which would provide customers with a further rate reduction of $37
million annually beginning in 2004. Also included in the filing is an
incentive regulatory plan, which would provide for additional rate reductions
through efficiencies derived as a result of Florida Power's ability to lower
the future costs of its utility operations. Florida Power filed supplemental
minimum filing requirements and testimony on November 15, 2001. Hearings are
scheduled to begin March 20, 2002, with a final decision expected in July
2002. The FPSC has encouraged its staff, Florida Power, and other parties to
negotiate a settlement, if possible, before the hearings begin. The Company
cannot predict the outcome or impact of these matters.
C. Plant-Related Deferred Costs
In 1988 rate orders, CP&L was ordered to remove from rate base and treat as
abandoned plant certain costs related to the Harris Plant. Abandoned plant
amortization related to the 1988 rate orders was completed in 1998 for the
wholesale and North Carolina retail jurisdictions and in 1999 for the South
Carolina retail jurisdiction. Amortization of plant abandonment costs is
included in depreciation and amortization expense and totaled $15.0 million
in 1999.
14. Risk Management Activities and Derivatives Transactions
The Company uses a variety of instruments, including swaps, options and
forward contracts, to manage exposure to fluctuations in commodity prices
and interest rates. Such instruments contain credit risk if the
counterparty fails to perform under the contract. The Company minimizes
such risk by performing credit reviews using, among other things, publicly
available credit ratings of such counterparties. Potential non-performance
by counterparties is not expected to have a material effect on the
consolidated financial position or consolidated results of operations of
the Company.
The Company engages in limited energy trading activities to optimize the
value of electricity and fuel contracts, as well as generating facilities.
These activities are accounted for at fair value.
A. Commodity Derivatives - Non-Trading
The Company enters into certain forward contracts involving cash
settlements or physical delivery that reduce the exposure to market
fluctuations relative to the price and delivery of electric products.
During 2001, 2000 and 1999, the Company principally sold electricity
forward contracts, which can reduce price risk on the Company's available
but unsold generation. While such contracts are deemed to be economic
hedges, the Company no longer designates such contracts as hedges for
accounting purposes; therefore, these contracts are carried on the
consolidated balance sheet at fair value, with changes in fair value
recognized in earnings. Gains and losses from such contracts were not
material during 2001, 2000 and 1999. Also, the Company did not have
material outstanding positions in such contracts at December 31, 2001 or
2000. Most of the Company's commodity contracts either 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.
B. Commodity Derivatives - Trading
The Company from time to time engages in the trading of electricity
commodity derivatives and, therefore, experiences net open positions. The
Company manages open positions with strict policies which limit its
exposure to market risk and require daily reporting to management of
potential financial exposures. When such instruments are entered into for
trading purposes, the instruments are carried on the consolidated balance
sheet at fair value, with changes in fair value recognized in earnings. The
net results of such contracts have not been material in any year and the
Company did not have material outstanding positions in such contracts at
December 31, 2001 or 2000.
C. Other Derivative Instruments
The Company may from time to time enter into derivative instruments to
hedge interest rate risk or equity securities risk.
The Company has interest rate swap agreements to hedge its exposure on
variable rate debt positions. The agreements, with a total notional amount
of $500 million, were effective in July 2000 and mature in July 2002. Under
these agreements, the Company receives a floating rate based on the
three-month London Interbank Offered Rate (LIBOR) and pays a
weighted-average fixed rate of approximately 7.17%. The fair value of the
swaps was a $18.5 million liability position at December 31, 2001. Interest
rate swaps are carried on the balance sheet at fair value with the
unrealized gains or losses adjusted through other comprehensive income. As
such, payments or receipts on interest rate swap agreements are recognized
as adjustments to interest expense.
During 2000, the Company entered into forward starting swap agreements to
hedge its exposure to interest rates with regard to future issuances of
fixed-rate debt. The fair value of the swaps was a $37.5 million liability
position at December 31, 2000. During February 2001, as part of the
issuance of $3.2 billion of senior unsecured notes, the Company terminated
the forward starting swaps. The Company realized a $45.3 million loss on
these contracts, designated as cash flow hedges, that is deferred through
accumulated other comprehensive loss and amortized over the life of the
associated debt instruments.
The notional amounts of the interest rate swaps are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
15. Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the
provisions of Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees," and related interpretations as permitted under
SFAS 123, "Accounting for Stock-Based Compensation (SFAS 123).
A. Employee Stock Ownership Plan
The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership
Plan (401(k)) for which substantially all full-time non-bargaining unit
employees and certain part-time non-bargaining unit employees within
participating subsidiaries are eligible. Participating subsidiaries within
the Company as of January 1, 2002 were CP&L, NCNG, Florida Power, Progress
Telecom, Progress Fuels (Corporate) and Service Company. The 401(k), which
has Company matching and incentive goal features, encourages systematic
savings by employees and provides a method of acquiring Company common stock
and other diverse investments. The 401(k), as amended in 1989, is an Employee
Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire
Company common stock to satisfy 401(k) common share needs. Qualification as
an ESOP did not change the level of benefits received by employees under the
401(k). Common stock acquired with the proceeds of an ESOP loan is held by
the 401(k) Trustee in a suspense account. The common stock is released from
the suspense account and made available for allocation to participants as the
ESOP loan is repaid. Such allocations are used to partially meet common stock
needs related to Company matching and incentive contributions and/or
reinvested dividends. All or a portion of the dividends paid on ESOP suspense
shares and on ESOP shares allocated to participants may be used to repay ESOP
acquisition loans. To the extent used to repay such loans, the dividends are
deductible for income tax purposes.
There were 5,199,388 and 5,782,376 ESOP suspense shares at December 31, 2001
and 2000, respectively, with a fair value of $234.1 million and $284.4
million, respectively. ESOP shares allocated to plan participants totaled
14,088,173 and 13,732,670 at December 31, 2001 and 2000, respectively. The
Company's matching and incentive goal compensation cost under the 401(k) is
determined based on matching percentages and incentive goal attainment as
defined in the plan. Such compensation cost is allocated to participants'
accounts in the form of Company common stock, with the number of shares
determined by dividing compensation cost by the common stock market value at
the time of allocation. The Company currently meets common stock share needs
with open market purchases and with shares released from the ESOP suspense
account. Matching and incentive cost met with shares released from the
suspense account totaled approximately $18.2 million, $15.6 million and $16.3
million for the years ended December 31, 2001, 2000 and 1999, respectively.
The Company has a long-term note receivable from the 401(k) Trustee related
to the purchase of common stock from the Company in 1989. The balance of the
note receivable from the 401(k) Trustee is included in the determination of
unearned ESOP common stock, which reduces common stock equity. ESOP shares
that have not been committed to be released to participants' accounts are not
considered outstanding for the determination of earnings per common share.
Interest income on the note receivable and dividends on unallocated ESOP
shares are not recognized for financial statement purposes.
B. Stock Option Agreements
Pursuant to the Company's 1997 Equity Incentive Plan, Amended and Restated as
of September 26, 2001, the Company may grant options to purchase shares of
common stock to officers and eligible employees. Generally, options granted
vest one-third per year with 100 percent vesting at the end of year three.
The options expire 10 years from the date of grant. All option grants have an
exercise price equal to the fair market value of the Company's common stock
on the grant date. In October 2001, a grant of approximately 2.4 million
options was made at an exercise price of $43.49. There has been no other
significant stock option activity.
Compensation cost is measured for stock options as the difference between the
market price of the Company's common stock and the exercise price of the
option at the grant date. Accordingly, no compensation expense has been
recognized for the stock options granted.
Pro forma information regarding net income and earnings per share is required
by SFAS 123. Under this statement, compensation cost is measured at the grant
date based on the fair value of the award and is recognized over the vesting
period. The pro forma amounts have been determined as if the Company had
accounted for its employee stock options under SFAS 123. The fair value for
these options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions:
2001
--------
Risk-free interest rate(%) 4.83%
Dividend yield(%) 5.21%
Volatility factor(%) 26.47%
Weighted-average expected life of the options (in years) 10
The option valuation model requires the input of highly subjective
assumptions, primarily stock price volatility, changes in which can
materially affect the fair value estimate. The weighted-average fair value of
stock options granted during 2001 was approximately $8.00.
For purposes of the pro forma disclosures required by SFAS 123, the estimated
fair value of the options is amortized to expense over the options vesting
period. Compensation expense would have been $2.9 million in 2001 under SFAS
123. The Company's pro forma information is as follows (dollars in
thousands):
2001
--------
Net income:
As reported $541,610
Pro forma $539,845
Basic earnings per common share:
As reported $ 2.65
Pro forma $ 2.64
Diluted earnings per common share:
As reported $ 2.64
Pro forma $ 2.63
The effects of applying SFAS 123 in this pro forma disclosure are not likely
to be representative of effects on reported net income for future years.
The number of options outstanding as of December 31, 2001 was 2.3 million
with a weighted-average remaining contractual life of 9.75 years and a
weighted-average exercise price of $43.49. No options were exercisable as of
December 31, 2001.
C. Other Stock-Based Compensation Plans
The Company has additional compensation plans for officers and key employees
of the Company that are stock-based in whole or in part. The two primary
programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock
Awards program (RSA), both of which were established pursuant to the
Company's 1997 Equity Incentive Plan.
Under the terms of the PSSP, officers and key employees of the Company are
granted performance shares that vest over a three-year consecutive period.
Each performance share has a value that is equal to, and changes with, the
value of a share of the Company's common stock, and dividend equivalents are
accrued on, and reinvested in, the performance shares. The PSSP has two
equally weighted performance measures, both of which are based on the
Company's results as compared to a peer group of utilities. Compensation
expense is recognized over the vesting period based on the expected ultimate
cash payout. Compensation expense is reduced by any forfeitures.
The RSA allows the Company to grant shares of restricted common stock to
officers and key employees of the Company. The restricted shares vest on a
graded vesting schedule over a minimum of three years. Compensation expense,
which is based on the fair value of common stock at the grant date, is
recognized over the applicable vesting period, with corresponding increases
in common stock equity. The weighted average price of restricted shares at
the grant date was $41.86, $36.97 and $37.63 in 2001, 2000 and 1999,
respectively. Compensation expense is reduced by any forfeitures. Restricted
shares are not included as shares outstanding in the basic earnings per share
calculation until the shares are no longer forfeitable. Changes in restricted
stock shares outstanding were:
2001 2000 1999
------ ------ ------
Beginning balance 653,344 331,900 265,300
Granted 113,651 359,844 66,600
Vested (21,722) - -
Forfeited (70,762) (38,400) -
-------------------------------------
Ending balance 674,511 653,344 331,900
=====================================
The total amount expensed for other stock-based compensation plans was $14.3
million, $15.6 million and $2.2 million in 2001, 2000 and 1999, respectively.
16. Postretirement Benefit Plans
The Company and some of its subsidiaries have a non-contributory 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.
The components of net periodic pension benefit for the years ended December
31 are (in thousands):
2001 2000 1999
--------- -------- ---------
Expected return on plan assets $(169,329) $(87,628) $ (75,124)
Service cost 31,863 22,123 20,467
Interest cost 96,200 56,924 46,846
Amortization of transition obligation 125 125 106
Amortization of prior service benefit (1,325) (1,314) (1,314)
Amortization of actuarial gain (4,989) (5,721) (3,932)
--------- -------- ---------
Net periodic pension benefit $ (47,455) $(15,491) $ (12,951)
========= ======== =========
In addition to the net periodic benefit reflected above, in 2000 the Company
recorded a charge of approximately $21.5 million to adjust one of its
supplementary defined benefit pension plans. The effect of the adjustment for
this plan is reflected in the actuarial loss (gain) line in the pension
obligation reconciliation below.
Prior service costs and benefits are amortized on a straight-line basis over
the average remaining service period of active participants. Actuarial gains
and losses in excess of 10% of the greater of the pension obligation or the
market-related value of assets are amortized over the average remaining
service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
2001 2000
---------- ----------
Pension obligation at January 1 $1,376,859 $ 688,124
Interest cost 96,200 56,924
Service cost 31,863 22,123
Benefit payments (86,010) (55,291)
Actuarial loss (gain) 13,164 39,798
Plan amendments 20,882 -
Acquisitions (acquisition adjustment) (62,221) 625,181
---------- ----------
Pension obligation at December 31 $1,390,737 $1,376,859
Fair value of plan assets at December 31 1,677,630 1,843,410
---------- ----------
Funded status $ 286,893 $ 466,551
Unrecognized transition obligation 370 495
Unrecognized prior service cost (benefit) 5,346 (16,861)
Unrecognized actuarial loss (gain) 111,600 (158,541)
---------- ----------
Prepaid pension cost at December 31, net $ 404,209 $ 291,644
========== ==========
The net prepaid pension cost of $404.2 million at December 31, 2001 is
recognized in the accompanying Consolidated Balance Sheets as prepaid pension
cost of $489.6 million and accrued benefit cost of $85.4 million, which is
included
in other liabilities and deferred credits. The net prepaid pension cost of
$291.6 million at December 31, 2000 is recognized in the accompanying
Consolidated Balance Sheets as prepaid pension cost of $373.2 million and
accrued benefit cost of $81.6 million, which is included in other liabilities
and deferred credits. The aggregate benefit obligation for those plans where
the accumulated benefit obligation exceeded the fair value of plan assets was
$85.4 million and $83.6 million at December 31, 2001 and 2000, respectively,
and those plans have no plan assets.
Reconciliations of the fair value of pension plan assets are (in thousands):
2001 2000
---------- -----------
Fair value of plan assets at January 1 $1,843,410 $ 947,143
Actual return on plan assets (84,254) 24,840
Benefit payments (86,010) (55,291)
Employer contributions 4,484 1,329
Acquisitions - 925,389
---------- -----------
Fair value of plan assets at December 31 $1,677,630 $ 1,843,410
========== ===========
The weighted-average discount rate used to measure the pension obligation was
7.5% in 2001 and 2000. The weighted-average rate of increase in future
compensation for non-bargaining unit employees used to measure the pension
obligation was 4.0% in 2001 and 2000 and 4.2% in 1999. The corresponding rate
of increase in future compensation for bargaining unit employees was 3.5% in
2001 and 2000. The expected long-term rate of return on pension plan assets
used in determining the net periodic pension cost was 9.25% in 2001, 2000 and
1999.
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 net periodic OPEB cost for the years ended December 31 are
(in thousands):
2001 2000 1999
--------- -------- --------
Expected return on plan assets $ (4,651) $ (4,045) $ (3,378)
Service cost 13,231 10,067 7,936
Interest cost 28,414 15,446 13,914
Amortization of prior service benefit 319 107 -
Amortization of transition obligation (4,701) (5,875) 5,760
Amortization of actuarial gain (592) (819) (1)
--------- -------- --------
Net periodic OPEB cost $ 41,422 $ 26,634 $ 24,231
========= ======== ========
Prior service costs and benefits are amortized on a straight-line basis over
the average remaining service period of active participants. Actuarial gains
and losses in excess of 10% of the greater of the OPEB obligation or the
market-related value of assets are amortized over the average remaining
service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
2001 2000
--------- ---------
OPEB obligation at January 1 $ 374,923 $ 213,488
Interest cost 28,414 15,446
Service cost 13,231 10,067
Benefit payments (17,207) (7,258)
Actuarial gain 27,428 (12,590)
Plan amendment (25,845) -
Acquisitions - 155,770
--------- ---------
OPEB obligation at December 31 $ 400,944 $ 374,923
Fair value of plan assets at December 31 55,529 54,642
--------- ---------
Funded status $(345,415) $(320,281)
Unrecognized transition obligation 33,129 70,715
Unrecognized prior service cost 7,675 955
Unrecognized actuarial loss (gain) 6,429 (25,060)
--------- ---------
Accrued OPEB cost at December 31 $(298,182) $(273,671)
========= =========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2001 2000
--------- ---------
Fair value of plan assets at January 1 $ 54,642 $43,235
Actual return on plan assets (444) 124
Acquisition - 11,283
Employer contribution 18,538 7,258
Benefits paid (17,207) (7,258)
-------- -------
Fair value of plan assets at December 31 $ 55,529 $54,642
======== =======
The assumptions used to measure the OPEB obligation and determine the net
periodic OPEB cost are:
2001 2000 1999
----- ---------- -----
Weighted-average long-term rate of return on plan assets 8.70% 9.20% 9.25%
Weighted-average discount rate 7.50% 7.50% 7.50%
Initial medical cost trend rate for pre-Medicare benefits 7.50% 7.2% - 7.5% 7.50%
Initial medical cost trend rate for post-Medicare benefits 7.50% 6.2% - 7.5% 7.25%
Ultimate medical cost trend rate 5.0% 5.0% - 5.3% 5.0%
Year ultimate medical cost trend rate is achieved 2008 2005-2009 2006
The medical cost trend rates were assumed to decrease gradually from the
initial rates to the ultimate rates. Assuming a 1% increase in the medical
cost trend rates, the aggregate of the service and interest cost components
of the net periodic OPEB cost for 2001 would increase by $5.6 million, and
the OPEB obligation at December 31, 2001, would increase by $35.3 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of the
service and interest cost components of the net periodic OPEB cost for 2001
would decrease by $4.8 million and the OPEB obligation at December 31, 2001,
would decrease by $32.3 million.
During 1999, the Company completed the acquisition of NCNG (See Note 2B).
During 2000, the Company completed the acquisition of FPC (See Note 2A).
NCNG's and FPC's pension and OPEB liabilities, assets and net periodic costs
are reflected in the above information as appropriate. Effective January 1,
2000, NCNG's benefit plans were merged with those of the Company. Certain of
FPC's non-bargaining unit benefit plans were merged with those of the Company
effective January 1, 2002.
Florida Power continues to recover qualified plan pension costs and OPEB
costs in rates as if the acquisition had not occurred. Accordingly, a portion
of the prepaid pension cost and a portion of the accrued OPEB cost reflected
in the tables above have a corresponding regulatory liability and regulatory
asset, respectively (See Note 2A). In addition, pursuant to its rate
treatment, for 2001 Florida Power recognized additional periodic pension
credit of $16.5 million and additional periodic OPEB cost of $3.5 million, as
compared to the amounts included in the net periodic information above.
17. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average of common
shares outstanding. Diluted earnings per share includes the effect of the
non-vested portion of restricted stock awards. The stock options
outstanding as of December 31, 2001 were anti-dilutive and therefore are
not included in diluted earnings per share. Restricted stock awards and
contingently issuable shares had a dilutive effect on earnings per share
for all three years and increased the weighted-average number of common
shares outstanding for dilutive purposes by 664,403 in 2001, 454,924 in
2000 and 290,474 in 1999. The weighted-average number of common shares
outstanding for dilutive purposes was 205.3 million, 157.6 million and
148.6 million for 2001, 2000 and 1999, respectively.
ESOP shares that have not been committed to be released to participants'
accounts are not considered outstanding for the determination of earnings
per common share. The weighted-average of these shares totaled 5.4 million,
5.7 million and 6.5 million for the years ended December 31, 2001, 2000 and
1999, respectively.
18. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. A regulatory asset or liability has been recognized for the
impact of tax expenses or benefits that are recovered or refunded in
different periods by the utilities pursuant to rate orders.
Accumulated deferred income tax (assets) liabilities at December 31 are (in
thousands):
2001 2000
---------- ----------
Accelerated depreciation and property
cost differences $1,812,743 $2,054,509
Deferred costs, net 82,566 63,085
Income tax credit carry forward (306,497) (103,754)
Miscellaneous other temporary differences, net (157,343) (150,969)
Valuation allowance 31,492 10,868
---------- ----------
Net accumulated deferred income
tax liability $1,462,961 $1,873,739
========== ==========
Total deferred income tax liabilities were $2.68 billion and $2.79 billion
at December 31, 2001 and 2000, respectively. Total deferred income tax
assets were $1.22 billion and $919 million at December 31, 2001 and 2000,
respectively. The net of deferred income tax liabilities and deferred
income tax assets is included on the Consolidated Balance Sheets under the
captions other current liabilities and accumulated deferred income taxes.
The Company established a valuation allowance of $10.9 million in 2000 and
established additional valuation allowances of $20.5 million during 2001
due to the uncertainty of realizing future tax benefits from certain state
net operating loss carryforwards.
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
2001 2000 1999
-------- ------- -------
Effective income tax rate (38.9)% 29.7% 40.3%
State income taxes, net of federal benefit (7.7) (4.8) (4.6)
AFUDC amortization (4.9) (5.1) (1.7)
Federal tax credits 93.5 12.2 1.4
Goodwill amortization and write-offs (11.3) (0.7) (0.3)
Investment tax credit amortization 5.9 4.2 1.6
ESOP dividend deduction 1.9 1.0 1.1
Interpath investment impairment (2.1) - -
Other differences, net (1.4) (1.5) (2.8)
-------- ------- -------
Statutory federal income tax rate 35.0% 35.0% 35.0%
======== ======= =======
Income tax expense (credit) is comprised of (in thousands):
2001 2000 1999
--------- -------- --------
Current - federal $ 185,309 $254,967 $253,140
state 52,433 61,309 48,075
Deferred - federal (356,160) (84,605) (30,011)
state (10,330) (10,761) (2,484)
Investment tax credit (22,895) (18,136) (10,299)
--------- -------- --------
Total income tax expense (benefit) $(151,643) $202,774 $258,421
========= ======== ========
The Company, through its subsidiaries, is a majority owner in five entities
and a minority owner in one entity that own facilities that produce
synthetic fuel as defined under the Internal Revenue Service Code (Code).
The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 of the Code (Section 29) if
certain requirements are satisfied, including a requirement that the
synthetic fuel differs significantly in chemical composition from the coal
used to produce such synthetic fuel. All entities have received private
letter rulings (PLR's) from the Internal Revenue Service (IRS) with respect
to their synthetic fuel operations. The PLR's do not limit the production
on which synthetic fuel credits may be claimed. Should the tax credits be
denied on future audits, and the Company fails to prevail through the IRS
or legal process, there could be a significant tax liability owed for
previously-taken Section 29 credits, with a significant impact on earnings
and cash flows. In management's opinion, the Company is complying with all
the necessary requirements to be allowed such credits under Section 29 and
believes it is probable, although it cannot provide certainty, that it will
prevail on any credits taken.
19. Joint Ownership of Generating Facilities
CP&L and Florida Power hold undivided ownership interests in certain
jointly owned generating facilities, excluding related nuclear fuel and
inventories. Each is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. Each
also pays its ownership share of additional construction costs, fuel
inventory purchases and operating expenses. CP&L's and Florida Power's
share of expenses for the jointly owned facilities is included in the
appropriate expense category.
CP&L's and Florida Power's ownership interest in the jointly owned
generating facilities are listed below with related information as of
December 31, 2001 (dollars in thousands):
Comany
Megawatt Ownership Plant Accumulated Accumulated Under
Subsidiary Facility Capability Interest Investment Depreciation Decommissioning Construction
---------- -------- ---------- -------- ---------- ------------ --------------- ------------
CP&L Mayo Plant 745 83.83% $ 460,026 $ 230,630 $ - $ 7,116
CP&L Harris Plant 860 83.83% 3,154,183 1,321,694 93,637 14,416
CP&L Brunswick Plant 1,631 81.67% 1,427,842 828,480 339,945 41,455
CP&L Roxboro Unit 4 700 87.06% 309,032 126,007 - 7,881
Florida Crystal River Plant 834 91.78% 773,835 469,840 333,939 25,723
Power
In the table above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Harris Plant.
20. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between CP&L and Power Agency, CP&L is obligated to purchase a percentage
of Power Agency's ownership capacity of, and energy from, the Harris Plant.
In 1993, CP&L and Power Agency entered into an agreement to restructure
portions of their contracts covering power supplies and interests in
jointly owned units. Under the terms of the 1993 agreement, CP&L increased
the amount of capacity and energy purchased from Power Agency's ownership
interest in the Harris Plant, and the buyback period was extended six years
through 2007. The estimated minimum annual payments for these purchases,
which reflect capacity costs, total approximately $32 million. These
contractual purchases totaled $33.3 million, $33.9 million and $36.5
million for 2001, 2000 and 1999, respectively. In 1987, the NCUC ordered
CP&L to reflect the recovery of the capacity portion of these costs on a
levelized basis over the original 15-year buyback period, thereby deferring
for future recovery the difference between such costs and
amounts collected through rates. At December 31, 2001 and 2000, CP&L had
deferred purchased capacity costs, including carrying costs accrued on the
deferred balances, of $32.5 million and $44.8 million, respectively.
Increased purchases (which are not being deferred for future recovery)
resulting from the 1993 agreement with Power Agency were approximately $29
million, $26 million and $23 million for 2001, 2000 and 1999, respectively.
CP&L has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit No.
2 (Rockport). The agreement provides for the purchase of 250 megawatts of
capacity through 2009 with minimum annual payments of approximately $31
million, representing capital-related capacity costs. Total purchases
(including transmission use charges) under the Rockport agreement amounted to
$62.8 million, $61.0 million and $59.2 million for 2001, 2000 and 1999,
respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the purchase
of power from Skygen Energy LLC's Broad River facility (Broad River). The
agreement provides for the purchase of approximately 500 megawatts of
capacity through 2016 with an original minimum annual payment of
approximately $16 million, primarily representing capital-related capacity
costs. The minimum annual payments will be indexed for inflation. Total
purchases under the Broad River agreement amounted to $35.9 million in 2001.
A separate long-term agreement for additional power from Broad River will
commence June 1, 2002. This agreement will provide for the purchase of
approximately 300 megawatts of capacity through 2022 with an original minimum
annual payment of approximately $16 million representing capital-related
capacity costs. The minimum annual payments will be indexed for inflation.
Florida Power has long-term contracts for approximately 460 megawatts of
purchased power with other utilities, including a contract with The Southern
Company for approximately 400 megawatts of purchased power annually through
2010. Florida Power can lower these purchases to approximately 200 megawatts
annually with a three-year notice. Total purchases under these agreements
amounted to $111.7 million and $104.5 million for 2001 and 2000,
respectively. Minimum purchases under these contracts, representing
capital-related capacity costs, are approximately $50 million annually
through 2003 and $30 million annually through 2006.
Both CP&L and Florida Power have ongoing purchased power contracts with
certain cogenerators (qualifying facilities) with expiration dates ranging
from 2002 to 2025. These purchased power contracts generally provide for
capacity and energy payments. Energy payments for the Florida Power contracts
are based on actual power taken under these contracts. Minimum expected
future capacity payments under these contracts as of December 31, 2001 are
$235.7 million, $244.3 million, $255.4 million, $267.9 million and $279.1
million for 2002-2006, respectively. CP&L has various pay-for-performance
contracts with qualifying facilities for approximately 300 megawatts of
capacity expiring at various times through 2009. Payments for both capacity
and energy are contingent upon the qualifying facilities' ability to
generate. Payments made under these contracts were $145.1 million in 2001,
$168.4 million in 2000 and $178.7 million in 1999.
Florida Power and CP&L have entered into various long-term contracts for
coal, gas and oil requirements of its generating plants. Estimated annual
payments for firm commitments of fuel purchases and transportation costs
under these contracts are approximately $1.5 billion, $1.2 billion, $992.8
million, $942.4 million and $944.4 million for 2002 through 2006,
respectively.
B. Other Commitments
The Company has certain future commitments related to four synthetic fuel
facilities purchased that provide for contingent payments (royalties) of up
to $11.4 million on sales from each plant annually through 2007. The related
agreements were amended in December 2001 to require the payment of minimum
annual royalties of approximately $6.6 million for each plant through 2007.
As a result of the amendment, the Company recorded a liability (included in
other liabilities and deferred credits on the Consolidated Balance Sheets)
and a deferred cost asset (included in other assets and deferred debits in
the Consolidated Balance Sheets) of approximately $134.0 million at December
31, 2001, representing the minimum amounts due through 2007, discounted at
6.05%. As of December 31, 2001, the portion of the asset and liability
recorded that was classified as current was $25.8 million. The deferred cost
asset will be amortized to expense each year as synthetic fuel sales are
made. The maximum amounts payable under these agreements remain unchanged.
Actual amounts accrued under these agreements were approximately $45.8
million in 2001 and $43.1 million in 2000.
The Company has entered into a joint venture to build an 850-mile natural gas
pipeline system to serve 14 eastern North Carolina counties. The Company has
agreed to fund approximately $22.0 million of the project. The entire project
is expected to be completed by the end of 2004.
Progress Ventures completed the acquisition of two electric generating
projects totaling approximately 1,100 megawatts for total cash consideration
of $345 million. The transaction included a power purchase agreement with the
seller through
December 31, 2004. In addition, there is a project management completion
agreement whereby the Company has assumed certain liabilities to facilitate
buildout of one of the projects.
In January 2002, Progress Ventures entered into a letter of intent to
acquire approximately 215 natural gas wells, 52 miles of intrastate gas
pipeline and 170 miles of gas-gathering systems. Total consideration of $153
million is expected to include $135 million in Company common stock and $18
million in cash. This transaction is expected to be completed during the
first quarter of 2002.
C. Insurance
CP&L and Florida Power are members of Nuclear Electric Insurance Limited
(NEIL), which provides primary and excess insurance coverage against
property damage to members' nuclear generating facilities. Under the primary
program, each company is insured for $500 million at each of it's respective
nuclear plants. In addition to primary coverage, NEIL also provides
decontamination, premature decommissioning and excess property insurance
with limits of $2.0 billion on the Brunswick and Harris Plants, and $1.1
billion on the Robinson and Crystal River 3 Plants.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. Both CP&L and Florida Power are insured
thereunder, following a twelve-week deductible period, for 52 weeks in the
amount of $3.5 million per week at each of the nuclear units. An additional
110 weeks of coverage is provided at 80% of the above weekly amount. For the
current policy period, the companies are subject to retrospective premium
assessments of up to approximately $30.1 million with respect to the primary
coverage, $33.2 million with respect to the decontamination, decommissioning
and excess property coverage, and $22.6 million for the incremental
replacement power costs coverage, in the event covered losses at insured
facilities exceed premiums, reserves, reinsurance and other NEIL resources.
Pursuant to regulations of the NRC, each company's property damage insurance
policies provide that all proceeds from such insurance be applied, first, to
place the plant in a safe and stable condition after an accident and,
second, to decontamination costs, before any proceeds can be used for
decommissioning, plant repair or restoration. Each company is responsible to
the extent losses may exceed limits of the coverage described above.
Both CP&L and Florida Power are insured against public liability for a
nuclear incident up to $9.54 billion per occurrence. Under the current
provisions of the Price Anderson Act, which limits liability for accidents
at nuclear power plants, each company, as an owner of nuclear units, can be
assessed for a portion of any third-party liability claims arising from an
accident at any commercial nuclear power plant in the United States. In the
event that public liability claims from an insured nuclear incident exceed
$200 million (currently available through commercial insurers), each company
would be subject to pro rata assessments of up to $88.1 million for each
reactor owned per occurrence. Payment of such assessments would be made over
time as necessary to limit the payment in any one year to no more than $10
million per reactor owned. The Price Anderson Act expires August 1, 2002.
There are several renewal proposals before Congress which include possible
increased limits and retroactive premiums. The final outcome of this matter
cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear
liability insurance policies regarding the maximum recoveries available for
multiple terrorism occurrences. Under the NEIL policies, if there were
multiple terrorism losses occurring within one year after the first loss
from terrorism, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant. If
terrorism losses occurred beyond the one-year period, a new set of limits
and resources would apply. For nuclear liability claims arising out of
terrorist acts, the primary level available through commercial insurers is
now subject to an industry aggregate limit of $200.0 million. The second
level of coverage obtained through the assessments discussed above would
continue to apply to losses exceeding $200.0 million and would provide
coverage in excess of any diminished primary limits due to the terrorist
acts aggregate.
CP&L and Florida Power self-insure their transmission and distribution lines
against loss due to storm damage and other natural disasters. Florida Power
accrues $6 million annually to a storm damage reserve pursuant to a
regulatory order and may defer losses in excess of the reserve (Note 13B).
D. Claims and uncertainties
1. The Company is subject to federal, state and local regulations addressing
air and water quality, hazardous and solid waste management and other
environmental matters.
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The lead or sole regulatory agency that is responsible for a
particular former coal tar site depends
largely upon the state in which the site is located. There are several
manufactured gas plant (MGP) sites to which both electric utilities and the
gas utility have some connection. In this regard, both electric utilities and
the gas utility, with other potentially responsible parties, are
participating in investigating and, if necessary, remediating former coal tar
sites with several regulatory agencies, including, but not limited to, the
U.S. Environmental Protection Agency (EPA), the Florida Department of
Environmental Protection (FDEP) and the North Carolina Department of
Environment and Natural Resources, Division of Waste Management (DWM).
Although the electric utilities and gas utility may incur costs at these
sites about which it has been notified, based upon current status of these
sites, the Company does not expect those costs to be material to its
consolidated financial position or results of operations. The Company has
accrued probable costs at certain of these sites.
Both electric utilities, the gas utility and Progress Ventures are
periodically notified by regulators such as the EPA and various state
agencies of their involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation. Although the
Company's subsidiaries may incur costs at the sites about which they have
been notified, based upon the current status of these sites, the Company does
not expect those costs to be material to the consolidated financial position
or results of operations of the Company.
There has been and may be further proposed Federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide and mercury
setting forth national caps and emission levels over an extended period of
time. This national multi-pollutant approach would have significant costs
which could be material to the Company's consolidated financial position or
results of operations. Some companies may seek recovery of the related cost
through rate adjustments or similar mechanisms. Progress Energy cannot
predict the outcome of this matter.
The EPA has been conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both CP&L and Florida Power were asked to provide information to the EPA as
part of this initiative and cooperated in providing the requested
information. The EPA has initiated civil enforcement actions against other
unaffiliated utilities as part of this initiative, some of which have
resulted in settlement agreements calling for expenditures, ranging from $1.0
billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for $300
million. 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.
The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the issue of regional
transport of ozone. This rule is commonly known as the NOx SIP Call. The
EPA's rule requires 23 jurisdictions, including North and South Carolina,
Georgia, but not Florida, to further reduce nitrogen oxide emissions in order
to attain a pre-set state NOx emission level by May 31, 2004. CP&L is
evaluating necessary measures to comply with the rule and estimates its
related capital expenditures to meet these measures in North and South
Carolina could be approximately $370 million, which has not been adjusted for
inflation. 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. The Company
cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new eight-hour
ozone standard. In October 1999, the District of Columbia Circuit Court of
Appeals ruled against the EPA with regard to the federal eight-hour ozone
standard. The U.S. Supreme Court has upheld, in part, the District of
Columbia Circuit Court of Appeals decision. Further litigation and rulemaking
are anticipated. North Carolina adopted the federal eight-hour ozone standard
and is proceeding with the implementation process. North Carolina has
promulgated final regulations, which will require CP&L to install nitrogen
oxide controls under the State's eight-hour standard. The cost of those
controls are included in the cost estimate of $370 million set forth above.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act, which requires certain sources to make reductions in nitrogen
oxide emissions by May 1, 2003. The final rule also includes a set of
regulations that affect nitrogen oxide emissions from sources included in the
petitions. The North Carolina fossil-fueled electric generating plants are
included in these petitions. Acceptable state plans under the NOx SIP Call
can be approved in lieu of the final rules the EPA approved as part of the
126 petitions. CP&L, other utilities, trade organizations and other states
participated in litigation challenging the EPA's action. On May 15, 2001, the
District of Columbia Circuit Court of Appeals ruled in favor of the EPA which
will require North Carolina to make reductions in nitrogen oxide emissions by
May 1, 2003. However, the Court in its May 15/th/ decision rejected the EPA's
methodology for estimating the future growth factors the EPA used in
calculating the emissions limits for utilities. In August 2001, the court
granted a request by CP&L and other utilities to delay the implementation of
the 126 Rule for electric generating units pending resolution by the EPA of
the growth factor issue. The court's order tolls the three-year compliance
period (originally set to end on May 1, 2003) for electric generating units
as of May 15, 2001. On January 16, 2002, the EPA issued a memo to harmonize
the compliance dates for the Section 126 Rule and
the NOx SIP Call. The new compliance date for all affected sources is now
May 31, 2004, rather than May 1, 2003, subject to the completion of the
EPA's response to the related court decision on the growth factor issue. The
Company cannot predict the outcome of this matter.
On November 1, 2001, the Company completed the sale of the Inland Marine
Transportation segment to AEP Resources, Inc. In connection with the sale,
the Company entered into environmental indemnification provisions covering
both unknown and known sites. The Company has recorded an accrual to cover
estimated probable future environmental expenditures. The Company believes
that it is reasonably possible that additional costs, which cannot be
currently estimated, may be incurred related to the environmental
indemnification provision beyond the amounts accrued. The Company cannot
predict the outcome of this matter.
CP&L, Florida Power, Progress Ventures and NCNG have filed claims with the
Company's general liability insurance carriers to recover costs arising out
of actual or potential environmental liabilities. Some claims have been
settled and others are still pending. While management 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.
2. As required under the Nuclear Waste Policy Act of 1982, CP&L and Florida
Power each entered into a contract with the DOE under which the DOE agreed
to begin taking spent nuclear fuel by no later than January 31, 1998. All
similarly situated utilities were required to sign the same standard
contract.
In April 1995, the DOE issued a final interpretation that it did not have an
unconditional obligation to take spent nuclear fuel by January 31, 1998. In
Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's
-------------------------------
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan Power
------------------------
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
------ --------
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
-------------------------
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that their delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals found
that the delay was not unavoidable, but did not order the DOE to begin taking
spent nuclear fuel, stating that the utilities had a potentially adequate
remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998,
a group of utilities filed a motion with the Court of Appeals to enforce the
mandate in NSP v. DOE. Specifically, this group of utilities asked the Court
----------
to permit the utilities to escrow their waste fee payments, to order the DOE
not to use the waste fund to pay damages to the utilities, and to order the
DOE to establish a schedule for disposal of spent nuclear fuel. The Court
denied this motion based primarily on the grounds that a review of the matter
was premature, and that some of the requested remedies fell outside of the
mandate in NSP v. DOE.
----------
Subsequently, a number of utilities each filed an action for damages in the
Court of Claims. In a recent decision, the U.S. Circuit Court of Appeals
(Federal Circuit) ruled that utilities may sue the DOE for damages in the
Federal Court of Claims instead of having to file an administrative claim
with DOE. CP&L and Florida Power are in the process of evaluating whether
they should each file a similar action for damages.
CP&L and Florida Power also continue to monitor legislation that has been
introduced in Congress which might provide some limited relief. CP&L and
Florida Power cannot predict the outcome of this matter.
With certain modifications, CP&L's spent nuclear fuel storage facilities will
be sufficient to provide storage space for spent fuel generated on CP&L's
system through the expiration of the current operating licenses for all of
CP&L's nuclear generating units. Subsequent to the expiration of these
licenses, dry storage may be necessary. CP&L obtained NRC approval to use
additional storage space at the Harris Plant in December 2000. Florida Power
currently is storing spent nuclear fuel onsite in spent fuel pools. If
Florida Power does not seek renewal of the CR3 operating license, CR3 will
have sufficient storage capacity in place for fuel consumed through the end
of the expiration of the license in 2016. If Florida Power extends the CR3
operating license, dry storage may be necessary.
3. The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve substantial
amounts. Where appropriate, accruals have been made in accordance with SFAS
No. 5, "Accounting for Contingencies," to provide for such matters. In the
opinion of management, the final disposition of pending litigation would not
have a material adverse effect on the Company's consolidated results of
operations or financial position.