SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of report (date of earliest event reported):
February 18, 2003
Commission Exact name of registrants as specified in I.R.S. Employer
File Number their charters, state of incorporation, Identification Number
address of principal executive offices, and
telephone number
1-15929 Progress Energy, Inc. 56-2155481
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
The address of the registrant has not changed since the last report.
================================================================================
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS
The registrant files this Form 8-K Current Report for the purpose of filing the
exhibits listed below. Exhibits 99.1 and 99.2 are expected to be filed in
identical form with the registrant's Form 10-K Annual Report for the year ended
December 31, 2002.
(c) Exhibits.
23.1 Consent of Deloitte & Touche LLP
99.1 Management's Discussion and Analysis of Financial Condition and
Results of Operations
99.2 Progress Energy, Inc. financial statements:
Independent Auditors' Report - Deloitte & Touche LLP
Consolidated Statements of Income for the Years Ended December
31, 2002, 2001, and 2000
Consolidated Balance Sheets as of December 31, 2002 and 2001
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001, and 2000
Consolidated Statements of Changes in Common Stock Equity for
the Years Ended December 31, 2002, 2001 and 2000
Consolidated Quarterly Financial Data (Unaudited)
Notes to Consolidated Financial Statements
1
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
PROGRESS ENERGY, INC.
Registrant
By: /s/ Robert H. Bazemore, Jr.
---------------------------------
Robert H. Bazemore, Jr.
Vice President and Controller
Date: February 18, 2003
2
INDEX TO EXHIBITS
Exhibit
Number Description of Exhibit
23.1 Consent of Deloitte & Touche LLP
99.1 Management's Discussion and Analysis of Financial
Condition and Results of Operations
99.2 Progress Energy, Inc. financial statements:
Independent Auditors' Report - Deloitte & Touche LLP
Consolidated Statements of Income for the Years Ended
December 31, 2002, 2001, and 2000
Consolidated Balance Sheets as of December 31, 2002
and 2001
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2002, 2001, and 2000
Consolidated Statements of Changes in Common Stock
Equity for the Years Ended December 31, 2002, 2001
and 2000
Consolidated Quarterly Financial Data (Unaudited)
Notes to Consolidated Financial Statements
3
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-33520 on Form S-8, Post-Effective Amendment 1 to Registration Statement No.
33-38349 on Form S-3, Registration Statement No. 333-81278 on Form S-3,
Registration Statement No. 333-81278-01 on Form S-3, Registration Statement No.
333-81278-02 on Form S-3, Registration Statement No. 333-81278-03 on Form S-3,
Post-Effective Amendment 1 to Registration Statement No. 333-69738 on Form S-3,
Registration Statement No. 333-70332 on Form S-8, Registration Statement No.
333-87274, Post-Effective Amendment 1 to Registration Statement No. 333-47910 on
Form S-3, Registration Statement No. 333-52328 on Form S-8, Post-Effective
Amendment 1 to Registration Statement No. 333-89685 on Form S-8, and
Registration Statement No. 333-48164 on Form S-8 of Progress Energy, Inc. of our
report dated February 12, 2003, appearing in this Form 8-K of Progress Energy,
Inc.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
February 18, 2003
4
EXHIBIT 99.1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following Management's Discussion and Analysis contains forward-looking
statements that involve estimates, projections, goals, forecasts, assumptions,
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. Please review
"SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors
that may impact any such forward-looking statements made herein.
RESULTS OF OPERATIONS
For 2002 as compared to 2001 and 2001 as compared to 2000
In this section, earnings and the factors affecting earnings are discussed. The
discussion begins with a general overview, then separately discusses earnings by
business segment.
Overview
Progress Energy, Inc. (Progress Energy or the Company) is a registered holding
company under the Public Utility Holding Company Act of 1935 (PUHCA), as
amended. Progress Energy and its subsidiaries are subject to the regulatory
provisions of PUHCA. Progress Energy 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 CP&L Energy, Inc, the newly created holding
company. On December 4, 2000, CP&L Energy, Inc. changed its name to Progress
Energy, Inc.
The Company acquired Florida Progress Corporation (FPC) on November 30, 2000.
The acquisition was accounted for using the purchase method of accounting. As a
result, the consolidated financial statements only reflect FPC's operations
subsequent to November 30, 2000.
Through its wholly owned regulated subsidiaries, CP&L and Florida Power
Corporation (Florida Power), Progress Energy is primarily engaged in the
generation, transmission, distribution and sale of electricity in portions of
North Carolina, South Carolina and Florida. Through the Progress Ventures
business segment, Progress Energy is involved in nonregulated generation
operations; natural gas exploration and production; coal fuel extraction,
manufacturing, and delivery; and energy marketing and trading activities.
Through the Rail Services business segment, Progress Energy engages in various
rail and railcar related services. Through the Other business segment, Progress
Energy engages in other nonregulated business areas including telecommunications
and holding company operations.
Effective January 1, 2003, CP&L, Florida Power, and Progress Ventures, Inc.
(PVI) began doing business under the names Progress Energy Carolinas, Inc.,
Progress Energy Florida, Inc., and Progress Energy Ventures, Inc., respectively.
The legal names of these entities have not changed and there is no restructuring
of any kind related to the name change. The current corporate and business unit
structure remains unchanged.
In 2002, the operations of North Carolina Natural Gas Corporation (NCNG),
previously reported in the Other segment, were reclassified to discontinued
operations and therefore were not included in the results from continuing
operations during the periods reported. See Note 3A to the Progress Energy
consolidated financial statements for discussion of the planned divestiture.
Progress Energy is an integrated energy company located principally in the
southeast region of the United States. The Company has more than 21,900
megawatts of generation capacity and serves approximately 3.0 million electric
and natural gas customers in portions of North Carolina, South Carolina and
Florida. CP&L's and Florida Power's utility operations are complementary, as
CP&L has a summer peaking demand, while Florida Power has a winter peaking
demand. In addition, CP&L's greater proportion of commercial and industrial
customers combined with Florida Power's greater proportion of residential
customers creates a more balanced customer base. The Company is dedicated to
delivering reliable, competitively priced energy.
In 2002, Progress Energy's net income was $528.4 million, a 2.4% decrease from
$541.6 million in 2001. Income from continuing operations was $552.2 million and
$540.4 million for 2002 and 2001, respectively. The decrease in net income in
2002 is primarily due to:
o $288.7 million of after-tax impairments and other charges (Progress Telecom,
Caronet, and Interpath Communications, Inc.), estimated impairment on assets
held for sale (Railcar Ltd.), and discontinued operations (NCNG) in 2002;
o the rate case settlement of Florida Power (one-time retroactive rate
reduction of $21.0 million after tax combined with a 9.25% prospective rate
reduction);
5
o increased operating expenses of $16.7 million after tax at CP&L related to
the ice storm in December 2002, and
o increased benefit costs and a lower pension credit, primarily at the
electric utilities.
Partially offsetting these items were:
o continued retail customer growth and usage (including weather impacts) at
the electric utilities;
o lower depreciation expense related to the Florida rate case settlement;
o $152.8 million of after-tax impairments and other charges attributable to
Strategic Resource Solutions Corp. (SRS) and Interpath Communications, Inc.
(Interpath) in 2001;
o impact of the change in market value of contingent value obligations of
$28.1 million;
o lower interest charges primarily at CP&L, and
o the elimination of goodwill amortization in 2002.
Basic earnings per share from net income decreased from $2.65 per share in 2001
to $2.43 per share in 2002 due to the factors outlined above and also from an
increase in the number of shares outstanding resulting from the common stock
issuances in 2001 and 2002. See Note 14 to the Progress Energy consolidated
financial statements for more information on the Company's common stock.
Net income in 2001 rose $63.2 million or 13.2% when compared to the 2000 net
income of $478.4 million. The increase in net income in 2001 is due primarily to
a full year of FPC's operations being included in the 2001 results, as FPC
contributed net income of $398.3 million for the year ended December 31, 2001.
Other factors contributing to the increase in net income in 2001 include
increases in tax credits from Progress Energy's share of synthetic fuel
facilities, continued customer growth at the electric utilities and decreases in
depreciation expense related to CP&L's accelerated cost recovery program.
Partially offsetting these increases were impairment and other after-tax charges
totaling $152.8 million, primarily attributable to SRS and the Company's
investment in Interpath, as well as increases in interest expense, goodwill
amortization related to the FPC acquisition and the impact of unfavorable
weather. Basic earnings per share decreased from $3.04 per share in 2000 to
$2.65 per share in 2001 due to the factors outlined above and also from an
increase in the number of shares outstanding resulting from the FPC acquisition
and an additional common stock issuance in August 2001.
Electric Segments
The electric segments are primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North Carolina and South
Carolina by CP&L Electric, and since November 30, 2000, in portions of Florida
by Florida Power Electric. CP&L Electric serves an area of approximately 34,000
square miles, with a population of more than 4.0 million. As of December 31,
2002, CP&L Electric provided electricity to approximately 1.3 million customers.
Florida Power Electric serves an area of approximately 20,000 square miles, with
a population of more than 5.0 million. As of December 31, 2002, Florida Power
provided electricity to approximately 1.5 million customers.
The operating results of both electric utilities are primarily influenced by
customer demand for electricity, the ability to control costs and regulatory
return on equity. Annual demand for electricity is based on the number of
customers and their annual usage, with usage largely impacted by weather. In
addition, the current economic conditions in the service territories may impact
the annual demand for electricity.
CP&L Electric
CP&L Electric contributed net income of $513.1 million, $468.3 million and
$373.8 million in 2002, 2001 and 2000, respectively. Included in these amounts
are wholesale energy marketing activities and immaterial trading activities,
which are managed by Progress Ventures on behalf of CP&L Electric, that
contributed net income of $60.0 million, $62.7 million, and $84.0 million in
2002, 2001 and 2000, respectively.
6
Revenues
CP&L's electric revenues for the years ended December 31, 2002, 2001 and 2000
and the percentage change by year and by customer class are as follows (in
millions):
---------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000
---------------------------------------------------------------------------------------------------
Residential $1,241 7.7% $1,152 3.5% $1,113
Commercial 832 6.0 785 5.9 741
Industrial 645 (1.4) 654 (3.7) 679
Governmental 78 4.0 75 (1.3) 76
------------- ------------- -------------
Total Retail Revenues 2,796 4.9 2,666 2.2 2,609
Wholesale 651 2.7 634 9.9 577
Unbilled 15 - (32) - 51
Miscellaneous 77 1.3 76 7.0 71
------------- ------------- -------------
Total Electric Revenues $3,539 5.8% $3,344 1.1% $3,308
---------------------------------------------------------------------------------------------------
CP&L's electric energy sales for 2002, 2001 and 2000 and the percentage change
by year and by customer class are as follows (in thousands of mWh):
---------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000
---------------------------------------------------------------------------------------------------
Residential 15,239 6.0% 14,372 2.0% 14,091
Commercial 12,468 4.1 11,972 4.7 11,432
Industrial 13,089 (1.8) 13,332 (7.7) 14,446
Governmental 1,437 1.0 1,423 - 1,423
------------- -------------- -------------
Total Retail Energy Sales 42,233 2.8 41,099 (0.7) 41,392
Wholesale 15,024 15.6 12,996 (10.9) 14,582
Unbilled 270 - (534) - 679
------------- -------------- -------------
Total mWh sales 57,527 7.4% 53,561 (5.5%) 56,653
---------------------------------------------------------------------------------------------------
CP&L's electric revenues increased $195.2 million from 2001 to 2002. During
2002, residential and commercial sales reflected continued growth in the number
of customers served by CP&L Electric, with approximately 26,000 new customers in
2002. Sales of energy and revenue increased in 2002 compared to 2001 for all
customer classes except industrial. Increases in retail sales of $129.9 million
and wholesale sales of $16.9 million were also driven by favorable weather
during 2002 when compared to 2001. Wholesale sales growth was partially offset
by price declines in the wholesale market.
Downturns in the economy during 2001 and continuing into 2002 impacted energy
usage throughout most of the industrial customer class. Total industrial revenue
declined during 2002 by $9.1 million and during 2001 by $25.0 million as the
number of industrial customers decreased due to a slowdown in the textile
industry, as well as a decrease in usage in the chemical industry.
Compared to 2000, 2001 residential and commercial revenues reflected continued
growth in the number of customers served by CP&L Electric partially offset by
milder weather in 2001. CP&L Electric added over 30,500 new customers in 2001.
Milder weather in 2001 accounted for a decrease in retail revenue of $63.0
million for the year compared to 2000. Total kWh sales to wholesale customers
decreased in 2001 from 2000 primarily due to mild weather. However, revenues
from wholesale customers increased in 2001 over 2000 due to the establishment of
new long-term contracts and the receipt of a termination payment on a long-term
contract in December 2001.
Expenses
CP&L Electric's fuel expense increased $114.1 million in 2002, when compared to
$647.3 million in 2001, primarily due to an 8.2% increase in generation with a
higher percentage of generation being produced by combustion turbines, which
have higher fuel costs. CP&L Electric's fuel expense increased $19.8 million in
2001 compared to $627.5 million in 2000 primarily due to increases in the price
of coal, partially offset by decreases in generation.
For 2002, purchased power decreased $6.1 million, when compared to $353.6
million in 2001, mainly due to decreases in price and volume purchased. For
2001, purchased power increased $28.2 million when compared to $325.4 million in
2000 mainly due to favorable market conditions in the first quarter of 2001.
7
Fuel expenses are recovered primarily through cost recovery clauses and, as
such, have no material impact on operating results.
CP&L Electric's total operations and maintenance expenses increased $91.0
million in 2002 when compared to $701.7 million in 2001 primarily due to storm
costs of $27.2 million (see below), a lower pension credit of $6.0 million, the
establishment of an inventory reserve of $10.5 million for materials that have
no future benefit, increased salaries and benefits and other increases in
maintenance and outage support. CP&L Electric's operations and maintenance
expenses decreased $24.6 million in 2001 when compared to $726.3 million in
2000, primarily due to the absence of restoration costs associated with the
severe winter storm and record-breaking snowfall in January 2000, as well as
cost control efforts. These amounts were partially offset by increases in
planned nuclear outage costs and transmission expenses in 2001.
A major ice storm struck central North Carolina on December 4, 2002. As a result
of the storm, up to 464,000 (35%) customers in CP&L Electric's service area were
without power. Restoration included more than 3,500 line, service and tree
personnel from 19 states. The outages resulted in $27.2 million of increased
operations and maintenance costs and $27.8 million of increased capital costs.
Depreciation and amortization expense increased $1.9 million in 2002 when
compared to $521.9 million in 2001 and decreased $176.7 million in 2001 when
compared to $698.6 million in 2000. CP&L Electric's accelerated cost recovery
program for nuclear generating assets allows flexibility in recording
accelerated depreciation expense. CP&L Electric recorded $52.8 million of
accelerated depreciation expense in 2002 and $75.0 million in 2001. The
year-over-year favorability was offset by additional depreciation recognized in
2002, as compared to 2001, on new assets that were placed in service during
2002. In 2000, as approved by regulators, CP&L Electric recorded $275.0 million
of depreciation expense under the accelerated cost recovery program. See Note 1G
to the Progress Energy consolidated financial statements for additional
information about this program.
Net interest expense decreased $29.9 million in 2002, when compared to $241.4
million in 2001, due primarily to reduced debt and lower interest rates. Net
interest expense increased $19.6 million in 2001, when compared to $221.9
million in 2000, primarily due to higher debt balances used to fund construction
programs.
In accordance with an SEC order under PUHCA, effective in 2002, tax benefits not
related to acquisition interest expense that were previously held unallocated at
the holding company must be allocated to the profitable subsidiaries. As a
result, $34.1 million of the tax benefit that was previously held at the holding
company, included in the Other segment, was allocated to CP&L Electric in 2002.
The allocation has no impact on the Company's consolidated tax expense or net
income. Other fluctuations in income taxes are primarily due to changes in
pre-tax income.
Florida Power Electric
The results shown in the Progress Energy consolidated financial statements for
the Florida Power Electric segment include operating results since the date of
acquisition, November 30, 2000. Therefore, 2002 and 2001 include full years of
operations, while 2000 includes only one month. As a result, the 2000 results of
operations are not comparable to 2001.
Florida Power Electric contributed income of $322.6 million and $309.6 million
for the years ended December 31, 2002 and 2001, respectively, and $21.8 million
for the month of December 2000. Included in these amounts are wholesale energy
marketing activities and immaterial trading activities, which are managed by
Progress Ventures on behalf of Florida Power Electric, that contributed net
income of $13.0 million and $24.0 million for the years ended December 31, 2002
and 2001, respectively, and $1.7 million for the month of December 2000.
Florida Power Electric's earnings in 2002 were affected by the outcome of the
Florida Power rate case settlement, which included a one-time retroactive
revenue refund of $35.0 million ($21.0 million after tax), a decrease in retail
rates of 9.25% (effective May 1, 2002), which resulted in an additional $79.5
million decline in revenues, and an estimated revenue sharing refund of $4.7
million. These revenue declines were partially offset by $78.2 million of lower
depreciation and amortization pursuant to the rate case and increased service
revenue rates. See Note 15B to the Progress Energy consolidated financial
statements for further discussion of the rate case settlement.
8
A comparison of the results of operations of Florida Power Electric for the past
three years follows.
Revenues
Florida Power's electric revenues for the years ended December 31, 2002, 2001
and 2000 and the percentage change by year and by customer class, as well as the
impact of the rate case settlement on revenue, are as follows (in millions):
------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000 (a)
------------------------------------------------------------------------------------------------
Residential $1,645 0.1% $1,643 11.3% $1,476
Commercial 731 (3.1) 754 13.9 662
Industrial 211 (5.4) 223 5.2 212
Governmental 173 (1.7) 176 15.8 152
Revenue Sharing Refund (5) - - - -
Retroactive Retail Rate Refund (35) - - - -
---------- ------------ -----------
Total Retail Revenues 2,720 (2.7) 2,796 11.8 2,502
Wholesale 230 (20.1) 288 4.3 276
Unbilled (3) - (22) - 18
Miscellaneous 115 (23.8) 151 98.7 76
---------- ------------ -----------
Total Electric Revenues $3,062 (4.7)% $3,213 11.9% $2,872
------------------------------------------------------------------------------------------------
(a) Florida Power electric revenues are included in the Company's
results of operations since November 30, 2000, the date of
acquisition. Florida Power Electric's full year of revenue is
included for comparative purposes only.
Florida Power's electric energy sales for the years ended December 31, 2002,
2001 and 2000 and the percentage change by year and by customer class are as
follows (in thousands of mWh):
------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000 (b)
------------------------------------------------------------------------------------------------
Residential 18,754 6.5% 17,604 2.9% 17,116
Commercial 11,420 3.2 11,061 2.3 10,813
Industrial 3,835 (1.0) 3,872 (8.9) 4,249
Governmental 2,850 4.5 2,726 2.7 2,654
---------- ------------ -----------
Total Retail Energy Sales 36,859 4.5 35,263 1.2 34,832
Wholesale 4,180 (11.4) 4,719 (9.4) 5,209
Unbilled 5 - (511) - 344
---------- ------------ -----------
Total mWh sales 41,044 4.0% 39,471 (2.3%) 40,385
------------------------------------------------------------------------------------------------
(b) Florida Power electric energy sales are included in the Company's
results of operations since November 30, 2000, the date of
acquisition. Florida Power's full year of sales is included for
comparative purposes only.
Florida Power electric revenues decreased $151.1 million from 2001 to 2002. The
revenue declines were driven by the $119.2 million impact of the rate case,
mentioned previously. Additionally, wholesale revenues declined $58.1 million,
driven primarily by a contract that was not renewed. Year-over-year comparisons
were also unfavorably impacted by the recognition of $63.0 million of revenue
deferred from 2000 to 2001. Partially offsetting the unfavorable revenue impacts
was growth in the residential (approximately 29,000 additional customers) and
commercial (approximately 4,000 additional customers) customer classes.
Additional offsets included weather conditions, primarily a warmer than normal
summer in 2002, and an increase in other service revenue, resulting primarily
from increased rates allowed under the rate case settlement, along with higher
transmission wheeling revenues.
Residential and commercial sales increased in 2001 and reflect continued growth
in the number of customers served by Florida Power Electric, partially offset by
milder weather and a downturn in the economy. Florida Power Electric added over
35,000 new customers in 2001. Industrial sales declined in 2001 due to weakness
in the manufacturing sector and phosphate industry, which were affected by the
economic downturn. Sales to wholesale customers decreased for 2001, primarily
due to the mild weather.
Expenses
Fuel used in generation and purchased power was $1.37 billion for the year ended
December 31, 2002, a decrease of $58.8 million from 2001. The decrease is
primarily due to a lower recovery of fuel expense that resulted from a
mid-course correction of Florida Power Electric's fuel cost recovery clause, as
part of the rate settlement, and lower purchased power costs, partially offset
by an increase in coal prices and volume from high system requirements. Fuel and
purchased power expenses are recovered primarily through cost recovery clauses
and, as such, have no material impact on operating results. Fuel used in
generation and purchased power was $1.43 billion for the year ended December 31,
2001 and $94.8 million for the one month of 2000.
9
Operations and maintenance expense increased $85.1 million in 2002 when compared
to $487.1 million in 2001, due primarily to a reduced pension credit of $30.8
million, increased costs related to the Commitment to Excellence program of
$11.3 million, and an increase in other salary and benefit costs of $21.5
million related partially to increased medical costs. The Commitment to
Excellence program was initiated in 2002 to improve service and reliability.
Operations and maintenance expense was $152.7 million for the one month of 2000
and included merger-related charges.
Depreciation and amortization expense decreased $158.1 million in 2002 when
compared to $453.0 million in 2001. In addition to the depreciation and
amortization reduction of approximately $79.0 million related to the rate case,
depreciation declined an additional $97.0 million related to accelerated
amortization on the Tiger Bay regulatory asset, which was created as a result of
the early termination of certain long-term cogeneration contracts. See Note 15B
to the Progress Energy consolidated financial statements for further detail on
the rate case. Florida Power Electric amortizes the regulatory asset according
to a plan approved by the Florida Public Service Commission in 1997 and plans to
fully amortize the asset by the end of 2003. In 2001, $97.0 million of
accelerated amortization was recorded on the Tiger Bay regulatory asset, of
which $63.0 million was associated with deferred revenue from 2000 and had no
impact on 2001 earnings. Depreciation and amortization expense was $28.9 million
for the one month of 2000.
In 2002, $19.9 million of the tax benefit that was previously held at the
Company's holding company (see earlier discussion in the CP&L Electric segment),
was allocated to Florida Power Electric. Other fluctuations in income taxes are
primarily due to changes in pretax income.
Diversified Businesses
The Company's diversified businesses consist primarily of the Progress Ventures
segment, the Rail Services segment, and Progress Telecom, Caronet, SRS and
Holding Company operations, which are in the Other segment and are explained in
more detail below.
Progress Ventures
Progress Ventures contributed segment income of $271.1 million and $288.7
million for 2002 and 2001, respectively. These amounts included wholesale energy
marketing and immaterial trading net income of $73.0 million and $86.7 million
in 2002 and 2001, respectively, that Progress Ventures managed on behalf of the
utilities. Due to the creation of Progress Ventures in 2000 and the acquisition
of Progress Fuels' subsidiaries through the FPC acquisition, the results of
operations for the Progress Ventures segment are not comparable between 2001 and
2000.
The Progress Ventures segment operations include nonregulated generation
operations; natural gas exploration and production; coal fuel extraction,
manufacturing and delivery; and energy marketing and limited trading activities
on behalf of the utility operating companies as well as for its nonregulated
plants. Progress Ventures' results for 2002 were impacted unfavorably by the
weak energy market and lower synthetic fuel sales, offset partially by
additional earnings from placing in service additional nonregulated generation
plants and the purchase of Westchester Gas Company.
Progress Ventures' nonregulated generation operations generated net income of
$34.7 million and $4.3 million in 2002 and 2001, respectively. In 2001, the
operations included one merchant plant with a 315-megawatt capacity. In 2002, a
plant was transferred from the CP&L Electric regulated segment to Progress
Ventures, one operational plant was purchased from LG&E Energy Corporation
(LG&E. See Note 2A to the Progress Energy consolidated financial statements),
and one additional plant was placed into service upon completion of
construction. At the end of 2002, plants with 1,554 megawatts of capacity were
operational. This increase in capacity drove the increase in net income. The
earnings potential of the increased capacity was partially offset by the general
softness in the energy market in 2002. The Company has contracts representing
63%, 69%, and 25% of planned production capacity for 2003 through 2005,
respectively. The 2005 decline results from the expiration of four contracts.
The Company is actively pursuing opportunities with the current customers and
other potential customers.
Progress Ventures subsidiary, MPC Generating, LLC, had two tolling agreements
for output on one of its units with Dynegy, Inc. through June 2008. The
contracts with Dynegy were terminated in December 2002. The Company expects to
recognize a gain in connection with the termination in the first quarter of 2003
if certain related contingencies are resolved, but does not currently have a
customer for the output of the 160 megawatt unit.
10
In 2001, Progress Ventures' natural gas exploration and production operations
included the operations of Mesa Hydrocarbons, Inc. (Mesa), which owns natural
gas reserves and operates wells in Colorado and sells natural gas. In 2002, it
also included similar operations of Westchester Gas Company. See Note 2B to the
Progress Energy consolidated financial statements for discussion of the
Westchester Gas Company acquisition. These gas operations generated net income
of $9.6 million and $5.3 million in 2002 and 2001, respectively. Westchester Gas
Company produced 5.8 million cubic feet of gas in 2002, which represented 49% of
the combined production for the year. This increased production drove the
earnings increase from 2001 to 2002.
Progress Ventures' coal fuel extraction, manufacturing and delivery operations
generated net income of $166.4 million and $198.4 million in 2002 and 2001,
respectively. The Progress Ventures coal group produced and sold 11.2 million
and 13.3 million tons of synthetic fuel in 2002 and 2001. The production and
sale of the synthetic fuel from these facilities generate operating losses, but
qualify for tax credits under Section 29 of the Internal Revenue Code, which
more than offset the effects of such losses. See "Synthetic Fuels " under OTHER
MATTERS below for additional discussion of these tax credits. The sales resulted
in tax credits of $291.0 million and $349.3 million being recognized in 2002 and
2001, respectively. The Company is pursuing selling a portion of the synthetic
fuel operations.
Progress Ventures' energy marketing and trading operations generated net income
of $69.1 million and $86.7 million in 2002 and 2001, respectively. This group
focuses on marketing and selling wholesale power and limited financial trading.
Wholesale marketing generated $77.2 million and $90.2 million of the group's
earnings in 2002 and 2001, respectively. The earnings reductions from 2001 to
2002 are mainly attributable to reduced margins for wholesale electric sales.
This group also manages financial trades of power. Financial trades generated
net losses of $8.1 million and $3.5 million in 2002 and 2001, respectively,
including associated overhead costs. The primary driver of the increased loss in
2002 was the higher overhead associated with the plan to grow the marketing and
trading activities; however, the Company recently announced plans to reduce the
scope of its trading activities.
Rail Services
Rail Services' operations represent the activities of Progress Rail Services
Corporation (Progress Rail) and include railcar and locomotive repair,
trackwork, rail parts reconditioning and sales, scrap metal recycling, railcar
leasing and other rail related services. Rail Services' results for the year
ended December 31, 2001, include Rail Services' cumulative revenues and net loss
from the date of acquisition, November 30, 2000, because Rail Services had been
held for sale from the date of acquisition through the second quarter of 2001.
Progress Rail contributed net losses of $41.7 million and $12.1 million for the
years ended December 31, 2002 and 2001, respectively. The net loss in 2002
includes a $40.1 million after-tax estimated impairment on assets held for sale
related to Railcar Ltd., a leasing subsidiary of Progress Rail. The Company
intends to sell the assets of Railcar Ltd. in 2003 and has reported these assets
as assets held for sale. See Note 3B to the Progress Energy consolidated
financial statements for discussion of this planned divestiture. Rail Services'
results for both years were affected by a downturn in the overall economy,
decreases in rail service procurement by major railroads and a downturn in the
domestic scrap market. Progress Rail's 2002 results were favorably impacted by
aggressive cost cutting, new business opportunities and restructuring
initiatives.
An SEC order approving the merger of FPC requires the Company to divest of Rail
Services by November 30, 2003. The Company is actively pursuing alternatives,
but does not expect to find the right divestiture opportunity by that date.
Therefore, the Company plans to seek an extension from the SEC.
Other
Progress Energy's Other segment primarily includes the operations of SRS,
Progress Telecom and Caronet. The results of NCNG have been excluded from the
Other segment because of its classification as a discontinued operation. This
segment also includes other nonregulated operations of CP&L and FPC, as well as
holding company results and consolidation and elimination adjustments. The Other
segment had a net loss from continuing operations of $439.9 million and $427.4
million in 2002 and 2001, respectively, and net income from continuing
operations of $42.6 million in 2000. The increase in the net loss in 2002 was
primarily related to impairments and other charges in the telecommunications
group and the reallocation of favorable income tax benefits to other segments.
These charges are partially offset by the elimination of goodwill amortization
of $89.7 million and the favorable impact of the contingent value obligations,
which are discussed below. The decrease in earnings for 2001 when compared to
2000 is primarily due to after-tax charges of $148.1 million from the assessment
of the recoverability of the Interpath investment and certain assets in the SRS
subsidiary, increases in after-tax interest expense for holding company debt of
$159.0 million and goodwill amortization of $82.7 million resulting from the
acquisition of FPC. In addition, the Other segment net income in 2000 includes a
$121.1 million after-tax gain on sale of assets, as described more fully below.
11
SRS was engaged in software sales and energy services to help industrial,
commercial and institutional customers manage energy costs. In 2002, SRS
refocused the business on energy services in the southeastern United States and
consolidated remaining operations with other retail activities. SRS net losses,
excluding after-tax impairments and other charges discussed below, were $13.3
million, $7.2 million and $0.8 million for 2002, 2001 and 2000, respectively.
The earnings decline from 2001 to 2002 resulted from a $3.8 million loss on the
sale of the assets of several divisions and from increased legal fees. Due to
the historical losses at SRS and the decline of the market value for technology
companies, a valuation study was obtained to help assess the recoverability of
SRS's long-lived assets in 2001. Based on this assessment, an after-tax asset
impairment and other charges (primarily legal expenses) totaling $40.7 million
were recorded in 2001. See Note 7 to the Progress Energy consolidated financial
statements for further information on this impairment and other charges. In
addition, the Company recorded after-tax investment impairments of $4.9 million
for other-than-temporary declines in certain investments of SRS in 2001.
Progress Telecom and Caronet had combined net losses of $229.0 million and
$110.4 million for 2002 and 2001, respectively. In 2000, Caronet combined with
one month of Progress Telecom contributed net income of $79.9 million.
Progress Telecom and Caronet provide broadband capacity services, dark fiber and
wireless services in Florida and the eastern United States. Due to the decline
of the telecommunications industry and continued operating losses, the Company
obtained a valuation study in 2002 to assess the recoverability of Progress
Telecom's and Caronet's long-lived assets. Based on these valuation studies, the
Company recorded an after-tax impairment of $190.4 million and other related
after-tax charges, primarily inventory adjustments, of $18.1 million. See Note
7A to the Progress Energy consolidated financial statements for further
information on this impairment and other charges.
Effective June 28, 2000, Caronet contributed the net assets used in its
application service provider business to a newly formed company named Interpath
Communications, Inc. (Interpath). In May 2002, Interpath merged with a third
party, diluting Caronet's ownership interest from 35% to 19% and reduced the
voting interest from 15% to 7%. The Company obtained valuation studies in 2001
and again in 2002, after the merger of Interpath. As a result of these valuation
studies, the Company recorded impairments for other-than-temporary declines in
the fair value of its investment in Interpath of $16.3 million and $102.4
million in 2002 and 2001, respectively. See Note 7B to the Progress Energy
consolidated financial statements for further information on this impairment.
In 2000, Caronet sold its 10% limited partnership interest in BellSouth
Carolinas PCS, resulting in an after-tax gain of $121.1 million. See Note 3D to
the Progress Energy consolidated financial statements for further details on the
sale.
Excluding the impairments, other charges and the gain on the sale of the limited
partnership interest discussed above, Progress Telecom and Caronet had combined
remaining losses of $4.2 million, $8.0 million and $41.2 million for 2002, 2001
and 2000, respectively. Lower depreciation resulting from the write-down of
impaired assets contributed to the decrease in the remaining loss from 2002 to
2001. The reduction in the remaining loss in 2001, when compared to 2000,
results from the removal of the Interpath operations.
The Other segment also includes Progress Energy's holding company results. As
part of the acquisition of FPC, goodwill of approximately $3.6 billion was
recorded, and amortization of $89.7 million in 2001 and $7.0 million in 2000 was
included in the Other segment. In accordance with SFAS No. 142, "Goodwill and
Other Intangible Assets," effective January 1, 2002, the Company no longer
amortized goodwill. At December 31, 2002, the Company had approximately $3.7
billion of unamortized goodwill. See Note 6 to the Progress Energy consolidated
financial statements for more details on goodwill.
Net pre-tax interest charges in the Other segment were $270.2 million, $253.1
million and $5.2 million, for 2002, 2001 and 2000, respectively. The increase in
2002, when compared to 2001, was primarily related to increased debt associated
with the purchase of generating plants. This was partially offset by lower
interest rates and $18.9 million of interest capitalization in 2002 related to
the building of the nonregulated generating plants. The increase in interest
from 2000 to 2001 was primarily related to the debt used to finance the
acquisition of FPC.
According to an SEC order under PUHCA, Progress Energy's tax benefit not related
to acquisition interest expense is to be allocated to profitable subsidiaries.
Therefore, the tax benefit that was previously held in the holding company,
included in the Other segment, was allocated to the profitable subsidiaries
effective with 2002. The allocation has no impact on consolidated tax expense or
earnings. However, in 2002, the allocation increased the Other segment's tax
expense $55.4 million with offsetting decreases in other segments (primarily
CP&L Electric and Florida Power Electric).
12
Progress Energy issued 98.6 million contingent value obligations (CVOs) in
connection with the FPC acquisition. Each CVO represents the right to receive
contingent payments based on the performance of four synthetic fuel facilities
owned by Progress Energy. The payments, if any, are based on the net after-tax
cash flows the facilities generate. At December 31, 2002, 2001, and 2000, the
CVOs had a fair market value of approximately $13.8 million, $41.9 million, and
$40.4 million, respectively. Progress Energy recorded an unrealized gain of
$28.1 million for the year ended December 31, 2002, an unrealized loss of $1.5
million for the year ended December 31, 2001, and an unrealized gain of $8.9
million for the month ended December 31, 2000, to record the changes in fair
value of CVOs, which had average unit prices of $0.14, $0.43 and $0.41 at
December 31, 2002, 2001 and 2000, respectively.
Discontinued Operations
In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company,
Inc. As a result of this action, the operating results of NCNG were reclassified
to discontinued operations for all reportable periods. Progress Energy expects
to sell NCNG for net proceeds of approximately $400 million, which results in an
estimated after-tax loss on the sale of the assets of $29.4 million, including
the impact of interest expense allocated to NCNG, as discussed in Note 3A to the
Progress Energy consolidated financial statements.
Application of Critical Accounting Policies and Estimates
The Company prepared its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. In doing so,
certain estimates were made that were critical in nature to the results of
operations. The following discusses those significant estimates that may have a
material impact on the financial results of the Company and are subject to the
greatest amount of subjectivity. Senior management has discussed the development
and selection of these critical accounting policies with the Audit Committee of
the Company's Board of Directors.
Utility Regulation
The Company's regulated utilities segments are subject to regulation that sets
the prices (rates) the Company is permitted to charge customers based on the
costs that regulatory agencies determine the Company is permitted to recover. At
times, regulators permit the future recovery through rates of costs that would
be currently charged to expense by a nonregulated company. This ratemaking
process results in deferral of expense recognition and the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in each state in which the Company operates, a
significant amount of regulatory assets has been recorded. The Company
continually reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future. Additionally, the state regulatory agencies often provide
flexibility in the manner and timing of the depreciation of property, nuclear
decommissioning costs and amortization of the regulatory assets. Note 15 to the
Progress Energy consolidated financial statements provides additional
information related to the impact of utility regulation on the Company.
Asset Impairments
The Company evaluates the carrying value of long-lived assets for impairment
whenever indicators exist. Examples of these indicators include current period
losses combined with a history of losses, or a projection of continuing losses,
or a significant decrease in the market price of a long-lived asset group. If an
indicator exists, the asset group held and used is tested for recoverability by
comparing the carrying value to the sum of undiscounted expected future cash
flows directly attributable to the asset group. If the asset group is not
recoverable through undiscounted cash flows or if the asset group is to be
disposed of, an impairment loss is recognized for the difference between the
carrying value and the fair value of the asset group. A high degree of judgment
is required in developing estimates related to these evaluations and various
factors are considered, including projected revenues and cost and market
conditions.
During 2002, the Company recorded pre-tax long-lived asset impairments of $305.0
million related to its telecommunications business. See Note 7A to the Progress
Energy consolidated financial statements for further information on this
impairment and other charges. The fair value of these assets was determined
using an external valuation study heavily weighted on a discounted cash flow
methodology and using market approaches as supporting information. However, if
the telecommunications market continues to deteriorate, the Company's
telecommunications related assets may be further adversely affected.
The Company also continually reviews its investments to determine whether a
decline in fair value below the cost basis is other than temporary. During 2002
and 2001, the Company recorded pre-tax impairments to the cost method investment
in Interpath of $25.0 million and $156.7 million, respectively. The fair value
of this investment was determined using an external valuation study heavily
weighted on a discounted cash flow methodology and using market approaches as
supporting information. These cash flows include numerous assumptions including
the pace at which the telecommunications market will rebound. In the fourth
quarter of 2002, the Company sold its remaining interest in Interpath for a
nominal amount.
13
Goodwill
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets" which requires that goodwill be tested for impairment at
least annually and more frequently when indicators of impairment exist. See Note
6 to the Progress Energy consolidated financial statements for further detail on
goodwill. Accounting standards require a two step goodwill impairment test. The
first step, used to identify potential impairment, compares the fair value of
the reporting unit with its carrying amount, including goodwill. The second
step, used to measure the amount of the impairment loss if step one indicates a
potential impairment, compares the implied fair value of the reporting unit
goodwill with the carrying amount of the goodwill.
The Company completed the initial transitional goodwill impairment test, which
indicated that the Company's goodwill was not impaired as of January 1, 2002. In
addition, the Company performed the annual goodwill impairment test for CP&L
Electric and Florida Power Electric during 2002, which indicated that the
Company's goodwill was not impaired. In connection with the pending sale of
NCNG, the Company reviewed the carrying value of NCNG, including goodwill, as
discussed in Note 3A to the Progress Energy consolidated financial statements.
During 2002, the Company completed the acquisition of two electric generating
projects, Walton County Power, LLC and Washington County Power, LLC. The
acquisitions resulted in goodwill of $64.1 million. The Company has completed
the purchase price allocation and will perform the annual goodwill impairment
test in the first quarter of 2003. During 2002, the Company also acquired
Westchester Gas Company. The purchase price has been preliminarily allocated to
fixed assets including oil and gas properties, based on the preliminary fair
values of the assets acquired. The purchase price allocation for this
acquisition will be finalized in the second quarter of 2003, and if any of the
purchase price is ultimately allocated to goodwill, an annual goodwill
impairment test will be performed at that time.
Synthetic Fuels Tax Credits
Progress Energy, through the Progress Ventures business unit, produces synthetic
fuel from coal fines. The production and sale of the synthetic fuel qualifies
for tax credits under Section 29 of the Internal Revenue Code (Section 29) if
certain requirements are satisfied, including a requirement that the synthetic
fuel differs significantly in chemical composition from the feedstock used to
produce such synthetic fuel. Any synthetic fuel tax credit amounts not utilized
are carried forward indefinitely and are included in deferred taxes on the
accompanying Consolidated Balance Sheet. See Note 20 to the Progress Energy
consolidated financial statements for further information on the synthetic fuel
tax credits. All of Progress Energy's synthetic fuel facilities have received
private letter rulings from the Internal Revenue Service (IRS) with respect to
their operations. These tax credits are subject to review by the IRS, and if
Progress Energy fails to prevail through the administrative 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.
Pension and Other Postretirement Benefits
The Company's reported costs of providing pension and other postretirement
benefits (described in Note 18 to the Progress Energy consolidated financial
statements), primarily health benefits, are dependent on numerous factors
resulting from actual plan experience and assumptions of future experience. For
example, such costs are impacted by employee demographics, changes made to plan
provisions, and key actuarial assumptions such as rates of return on plan
assets, discount rates used in determining benefit obligations and annual costs
and, for other postretirement benefits, medical trend rates.
Due to a decline in market interest rates for high-quality (AAA/AA) debt
securities, which are used as the benchmark for setting the discount rate, the
Company lowered the discount rate to 6.60% at December 31, 2002, which will
increase the 2003 benefit costs recognized. In addition, the continuing declines
in the equity markets have adversely affected the fair value of plan assets,
which will also increase the benefit costs recognized in 2003. Evaluations of
the effects of these factors has not been completed, but the Company estimates
that 2003 total cost for pension and other postretirement benefits will increase
by approximately $40 million over the amount recorded in 2002, due in large part
to these factors. The majority of that increase has been anticipated and
reflected in the Company's budgeting/forecasting process. Recoveries in the
level of interest rates and equity markets would, correspondingly, have positive
effects on future years' benefit cost recognition.
14
The Company has substantial pension plan assets, with a fair value of
approximately $1.4 billion at December 31, 2002. The Company's expected rate of
return on pension plan assets has been, and will continue to be for the
foreseeable future, 9.25%. Under the accounting standard for pension accounting,
the expected rate of return used in pension cost recognition is a long-term rate
of return; therefore, the Company would only adjust that return if its
fundamental assessment of the debt and equity markets changes or its investment
policy changes significantly. The Company continues to believe that its pension
plan's investment mix supports the long-term rate of 9.25% being used. The
Company did not increase the expected long-term rate of return in response to
the abnormally high market return levels of the latter 1990s and does not
believe it is appropriate to adjust the rate downward because of recent market
declines. A 0.25% change in the expected rate of return for 2002 would have
changed 2002 pension cost by approximately $4.5 million.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Progress Energy is a registered holding company and, as such, has no operations
of its own. The ability to meet its obligations is primarily dependent on the
earnings and cash flows of its two electric utilities and the ability of those
subsidiaries to pay dividends or repay funds to Progress Energy.
The cash requirements of Progress Energy arise primarily from the
capital-intensive nature of its electric utility operations as well as the
expansion of its diversified businesses, primarily those of the Progress
Ventures segment.
Progress Energy relies upon its operating cash flow, generated primarily by its
two regulated electric utility subsidiaries, commercial paper facilities and its
ability to access long-term capital markets for its liquidity needs. Since a
substantial majority of Progress Energy's operating costs are related to its two
regulated electric utilities, a significant portion of these costs are recovered
from customers through fuel and energy cost recovery clauses.
During 2003, the Company expects to realize approximately $400 million of net
cash proceeds from the sale of NCNG. The Company also expects to receive between
$100 million and $300 million of proceeds through the sale of common stock
issued through the Progress Energy Direct Stock Purchase and Dividend
Reinvestment Plan, and its 401(k) Savings and Stock Ownership Plan.
Progress Energy's cash from operations and common stock issuance proceeds in
2003 are expected to fund its capital expenditures. Progress Energy expects to
use the proceeds from the sale of NCNG to reduce indebtedness then outstanding.
To the extent necessary, incremental borrowings or commercial paper issuances
may also be used as a source of liquidity.
Progress Energy forecasts its liquidity resources to be sufficient to fund its
current business plans. Risk factors associated with commercial paper backup
credit facilities and credit ratings are discussed below as well as in the
Company's SEC filings.
The following discussion of Progress Energy's liquidity and capital resources is
on a consolidated basis.
Cash Flows from Operations
Cash from operations is the primary source used to meet operating requirements
and capital expenditures. Total cash from operations for 2002 was $1.6 billion,
up $175 million from 2001.
The increase in cash from operating activities for 2001 when compared with 2000
is largely the result of the November 30, 2000, acquisition of FPC. The 2000
results reflected one month's cash from operations of FPC.
Progress Energy's two electric utilities produced approximately 112% of
consolidated cash from operations in 2002. It is expected that the two electric
utilities will continue to produce a majority of the consolidated cash flows
from operations over the next several years as its nonregulated investments,
primarily generation assets, are placed into service and begin generating
operating cash flows. In addition, Progress Ventures' synthetic fuel operations
do not currently produce positive operating cash flow primarily due to the
difference in timing of when tax credits are recognized for financial reporting
purposes and when tax credits are realized for tax purposes.
Total cash from operations provided the funding for approximately 72% of the
Company's property additions, nuclear fuel expenditures and diversified business
property additions during 2002. The remaining funds were obtained through debt
and equity issuances by Progress Energy as discussed below. Progress Energy
expects its operating cash flow to exceed its projected capital expenditures
beginning in 2004.
15
Investing Activities
Cash used in investing activities was $2.2 billion in 2002, up approximately
$556 million when compared with 2001. The increase is due primarily to the
expansion of PVI's generation portfolio. In February 2002, PVI purchased two
generating projects from LG&E Energy Corp. for approximately $350 million.
Cash used in investing was $1.7 billion in 2001, up $663 million when compared
with 2000 after adjusting for the acquisition of Florida Progress. The increase
is due primarily to the expansion of PVI's generation portfolio and the absence
of proceeds from the sale in 2000 of the BellSouth Carolinas PCS limited
partnership interest.
Capital expenditures for Progress Energy's regulated electric operations were
$1.2 billion or approximately 55% of consolidated capital expenditures in 2002.
As shown in the table below, the Company anticipates that the proportion of
nonregulated capital spending to total capital expenditures will decrease
substantially in 2003 when compared with 2002. The decrease reflects the
expected completion of Progress Ventures nonregulated generation portfolio by
the summer of 2003. Progress Energy expects the majority of its capital
expenditures to be incurred at its regulated operations.
(Dollars in millions):
Actual Forecasted
----------- ------------------------------------------------
2002 2003 2004 2005
----------- ------------ -------------- -----------
Regulated capital expenditures $ 1,174 $ 1,100 $ 1,050 $ 1,040
Nuclear fuel expenditures 81 120 100 120
AFUDC - borrowed funds (8) (20) (20) (20)
Nonregulated capital expenditures 935 290 110 110
----------- ------------ -------------- -----------
Total $ 2,182 $ 1,490 $ 1,240 $ 1,250
=========== ============ ============== ===========
Regulated capital expenditures in the table above include total expenditures
from 2003 through 2005 of approximately $147 million expected to be incurred at
regulated fossil-fueled electric generating facilities to comply with Section
110 of the Clean Air Act, referred to as the NOx SIP Call.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from coal-fired power plants. CP&L expects its capital costs to meet
these emission targets will be approximately $813 million by 2013. For the years
2003 through 2005, the Company expects to incur approximately $258 million of
total capital costs associated with this legislation, which is included in the
table above. See Note 24 to the Progress Energy consolidated financial
statements and "Current Regulatory Environment" under OTHER MATTERS below for
more information on this legislation.
CP&L has determined that its external funding levels do not fully meet the
nuclear decommissioning financial assurance levels required by the U.S. Nuclear
Regulatory Commission. The funding levels have been adversely affected by the
recent declines in the equity markets. The total shortfall is approximately $95
million (2010 dollars) for Robinson Unit No. 2, $82 million (2016 dollars) for
Brunswick Unit No. 1 and $99 million (2014 dollars) for Brunswick Unit No. 2.
CP&L is currently evaluating the alternatives for meeting the financial
assurance requirements, which primarily include increasing annual deposits to
the external trust by an estimated $18.8 million annually or obtaining a parent
company guarantee. The funding status for these facilities would be positively
affected by a recovery in the equity markets and by the approval of license
extension applications. See Note 1H to the Progress Energy consolidated
financial statements for further discussion.
All projected capital and investment expenditures are subject to periodic review
and revision and may vary significantly depending on a number of factors
including, but not limited to, industry restructuring, regulatory constraints,
market volatility and economic trends.
Financing Activities
Cash provided by financing activities increased approximately $433.8 million
over 2001, primarily due to issuances of long-term debt and common stock equity
by Progress Energy.
Cash provided by financing activities decreased by $3.4 billion when comparing
2001 to 2000. This decrease was due to the November 30, 2000, acquisition of
FPC, which was funded from the sale of short-term commercial paper. This funding
was converted to long-term debt during 2001. Excluding the effect of the
acquisition financing, cash from financing activities increased slightly in 2001
when compared with 2000, primarily due to the expansion of Progress Energy's
nonregulated operations.
16
In February 2002, $50 million of Progress Capital Holdings, Inc. (PCH)
medium-term notes, 5.78% Series, matured. Progress Energy funded this maturity
through the issuance of commercial paper. As of December 31, 2002, PCH has $223
million of fixed rate medium-term notes. The final medium-term note is due in
May 2008. Progress Energy intends to fund these maturing notes through
internally generated funds and the issuance of commercial paper.
In April 2002, Progress Energy issued $350 million of senior unsecured notes due
2007 with a coupon of 6.05% and $450 million of senior unsecured notes due 2012
with a coupon of 6.85%. Proceeds from this issuance were used to pay down
commercial paper, which had been used in part to fund the expansion of Progress
Ventures nonregulated generation portfolio, including the acquisition of
generating assets from LG&E.
In November 2002, Progress Energy issued 14.7 million shares of common stock.
Total net proceeds from the issuance were approximately $600 million and were
used to pay down commercial paper.
The Company issued 2.1 million shares representing approximately $86 million in
proceeds from its Dividend Reinvestment and Stock Purchase Plan, and its
employee benefit plans.
During 2002, both CP&L and Florida Power took advantage of historically low
interest rates and refinanced several issues of tax-exempt debt as well as
certain taxable issues.
In February 2002, CP&L issued $48.5 million principal amount of First Mortgage
Bonds, Pollution Control Series W, Wake County Pollution Control Revenue
Refunding Bonds, 5.375% Series 2002 Due February 1, 2017. On March 1, 2002, CP&L
redeemed $48.5 million principal amount of Pollution Control Revenue Bonds, Wake
County Due April 1, 2019, at 101.5% of the principal amount of such bonds.
In July 2002, Florida Power issued approximately $241 million of Pollution
Control Revenue Refunding Bonds, secured by First Mortgage Bonds. Proceeds from
this issuance were used to redeem $241 million of Pollution Control Revenue
Bonds in August. Also in July, $30 million of medium-term notes, 6.54% Series,
matured. Florida Power funded this maturity through the issuance of commercial
paper.
In July 2002, CP&L issued $500 million of senior unsecured notes due 2012 with a
coupon of 6.5%. Proceeds from this issuance were used to pay down commercial
paper, which had been used to redeem $500 million of CP&L Extendible Notes due
October 28, 2009, at 100% of the principal amount of such notes. These notes
were redeemed July 29, 2002.
In September 2002, CP&L redeemed $150 million of First Mortgage Bonds, 8.2%
Series, due July 1, 2022 at 103.55% of the principal amount of such bonds. CP&L
redeemed these notes through the issuance of commercial paper.
In March 2002, Progress Ventures obtained a $440 million bank facility that is
restricted for the use of expanding its nonregulated generation portfolio, which
is expected to be completed by the summer of 2003. Borrowings under this
facility will be nonrecourse to Progress Energy; however, the Company entered
into certain support and guarantee agreements to ensure performance under
generation construction and operating agreements. In September 2002, $130
million of the bank facility was terminated, reducing it to $310 million. This
amount includes a $50 million working capital facility. The reduction was due to
Progress Ventures' decision to reduce the expansion of its nonregulated
generation portfolio. As of December 31, 2002, $225 million was outstanding
under this facility.
As a registered holding company under PUHCA, Progress Energy obtains approval
from the SEC for the issuance and sale of securities as well as the
establishment of intracompany extensions of credit. In January 2002, Progress
Energy requested an increase of $2.5 billion in its authority to issue long-term
securities, increasing the limit from $5.0 billion to $7.5 billion. The SEC
approved the request on March 15, 2002. As of December 31, 2002, Progress Energy
has regulatory authority to issue approximately $1 billion of long-term
securities.
17
At December 31, 2002, the Company and its subsidiaries had committed lines of
credit totaling $1.74 billion, for which there were no loans outstanding. These
lines of credit support the Company's commercial paper borrowings. The following
table summarizes the Company's credit facilities (in millions):
Company Description Total
--------------------------------------------------------------------------
Progress Energy 364-Day (expiring 11/11/03) $ 430.2
Progress Energy 3-Year (expiring 11/13/04) 450.0
CP&L 364-Day (expiring 7/30/03) 285.0
CP&L 3-Year (expiring 7/31/05) 285.0
Florida Power 364-Day (expiring 4/01/03) 90.5
Florida Power 5-Year (expiring 11/30/03) 200.0
---------------
$ 1,740.7
===============
During 2002, in connection with renewals, the Progress Energy and Florida Power
364-day facilities were decreased by $120.0 million and $79.5 million,
respectively.
The Company's financial policy precludes issuing commercial paper in excess of
its supporting lines of credit. At December 31, 2002, the total amount of
commercial paper outstanding was $695 million, leaving approximately $1 billion
available for issuance. The Company is required to pay minimal annual commitment
fees to maintain its credit facilities.
In addition, these credit agreements and Progress Ventures' $310 million bank
facility contain various terms and conditions that could affect the Company's
ability to borrow under these facilities. These include a maximum debt to total
capital ratio, an interest coverage test, a material adverse change clause and
cross-default provisions.
All of the credit facilities and Progress Ventures' bank facility include a
defined maximum total debt to total capital ratio. Progress Energy's maximum
consolidated debt ratio reduces to 68% effective June 30, 2003. As of December
31, 2002, the calculated ratio for these four companies, pursuant to the terms
of the agreements, was as follows:
Company Maximum Ratio Actual Ratio (b)
------------------------------------------------------------------
Progress Energy, Inc. 70% (a) 62.4%
Carolina Power &Light Company 65% 52.7%
Florida Power Corporation 65% 48.6%
Progress Genco Ventures, LLC 40% 24.8%
(a) Progress Energy's maximum debt ratio reduces to 68% effective June
30, 2003.
(b) Indebtedness as defined by the bank agreements includes certain
letters of credit and guarantees which are not recorded on the
Consolidated Balance Sheets.
In November 2002, Progress Energy's 364-day credit facility was amended to add a
financial covenant for interest coverage. This covenant requires Progress
Energy's EBITDA to interest expense to be at least 2.5 to 1. As of December 31,
2002, this ratio was 3.43 to 1. Progress Ventures' bank facility requires a
minimum 1.25 to 1 debt service coverage ratio. As of December 31, 2002, Progress
Ventures' debt service coverage ratio was 7.65 to 1.
The credit facilities of Progress Energy, CP&L, Florida Power and PVI include a
provision under which lenders could refuse to advance funds in the event of a
material adverse change in the borrower's financial condition.
Each of these credit agreements contains cross-default provisions for defaults
of indebtedness in excess of $10 million. Under these provisions, if the
applicable borrower or certain subsidiaries fail to pay various debt obligations
in excess of $10 million the lenders could accelerate payment of any outstanding
borrowing and terminate their commitments to the credit facility. Progress
Energy's cross-default provision only applies to Progress Energy and its
significant subsidiaries (i.e. CP&L, Florida Progress, Florida Power, Progress
Capital Holdings, Inc., Progress Ventures, Inc. and Progress Fuels).
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other obligations of Progress Energy, not its
subsidiaries. In the event that these indenture cross-default provisions are
triggered, the debt holders could accelerate payment of approximately $4.8
billion in long-term debt. Certain agreements underlying the Company's
indebtedness also limit its ability to incur additional liens or engage in
certain types of sale and leaseback transactions.
The Company has on file with the SEC a shelf registration statement under which
senior notes, junior debentures, common and preferred stock and other trust
preferred securities are available for issuance by the Company. As of December
31, 2002, the Company had approximately $1 billion available under this shelf
registration.
18
Progress Energy and Florida Power each have an uncommitted bank bid facility
authorizing each of them to borrow and re-borrow, and have loans outstanding at
any time, up to $300 million and $100 million, respectively. At December 31,
2002, there were no outstanding loans against these facilities.
CP&L currently has on file with the SEC a shelf registration statement under
which it can issue up to $500 million of various long-term securities. Florida
Power currently has filed registration statements under which it can issue an
aggregate of $700 million of various long-term debt securities.
The following table shows Progress Energy's capital structure as of December 31,
2002 and 2001:
2002 2001
--------------------- ------------------
Common Stock 38.2% 36.7%
Preferred Stock 0.5% 0.6%
Total Debt 61.3% 62.7%
The amount and timing of future sales of company securities will depend on
market conditions, operating cash flow, asset sales and the specific needs of
the Company. The Company may from time to time sell securities beyond the amount
needed to meet capital requirements in order to allow for the early redemption
of long-term debt, the redemption of preferred stock, the reduction of
short-term debt or for other general corporate purposes.
Credit Rating Matters
As of February 7, 2003, the major credit rating agencies rated the Company's
securities as follows:
Moody's Standard
Investors Service and Poor's
Progress Energy, Inc.
Corporate Credit Rating Not Applicable BBB+
Senior Unsecured Baa2 BBB
Commercial Paper P-2 A-2
Carolina Power & Light Company
Corporate Credit Rating Not Applicable BBB+
Commercial Paper P-2 A-2
Senior Secured Debt A3 BBB+
Senior Unsecured Debt Baa1 BBB+
Subordinate Debt Baa2 BBB
Preferred Stock Baa3 BBB-
Florida Power Corporation
Corporate Credit Rating Not Applicable BBB+
Commercial Paper P-1 A-2
Senior Secured Debt A1 BBB+
Senior Unsecured Debt A2 BBB+
Preferred Stock Baa1 BBB-
FPC Capital I
Preferred Stock* Baa1 BBB-
Progress Capital Holdings, Inc.
Senior Unsecured Debt* A3 BBB
*Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies and no
assurances can be given that these ratings will continue for any given period of
time. However, the Company monitors its financial condition as well as market
conditions that could ultimately affect its credit ratings.
The Company and its subsidiaries' debt indentures and credit agreements do not
contain any "ratings triggers" which would cause the acceleration of interest
and principal payments in the event of a ratings downgrade. However, in the
event of a downgrade the Company and/or its subsidiaries may be subject to
increased interest costs on the credit facilities backing up the commercial
paper programs. The Company and its subsidiaries have certain contracts which
have provisions that are triggered by a ratings downgrade. These contracts
include counterparty trade agreements, derivative contracts, certain Progress
Energy guarantees and various types of third party purchase agreements. None of
these contracts would require any action on the part of Progress Energy or its
subsidiaries unless the ratings downgrade results in a rating below investment
grade.
19
In March 2002, Standard & Poor's affirmed Progress Energy's corporate credit
rating of BBB+ and the ratings of Florida Power and CP&L but revised the outlook
for all three entities to negative from stable. S&P stated that its change in
outlook reflected the increased business risk at PVI and lower-than-projected
credit protection measures. S&P stated that Progress Energy's plan to divest of
non-core assets and use the proceeds to pay down acquisition-related debt is
moving slower than S&P had expected. On September 4, 2002, S&P reaffirmed
Progress Energy's credit ratings and maintained the negative outlook. The
Company expects S&P to make a decision within the next 30 to 60 days. The
Company cannot predict the outcome of this matter.
On February 7, 2003, Moody's Investors Service announced that it was lowering
Progress Energy, Inc.'s senior unsecured debt rating from Baa1 to Baa2, and
changing the outlook of the rating from negative to stable. Moody's cited the
slower than planned pace of the Company's efforts to pay down debt from its
acquisition of Florida Progress as the primary reason for the ratings change.
Moody's also changed the outlook of Florida Power Corporation (A1 senior
secured) and Progress Capital Holding (A3 senior unsecured) from stable to
negative and lowered the trust preferred rating of FPC Capital I from A3 to Baa1
with a negative outlook.
The change in outlook by the rating agencies has not materially affected
Progress Energy's access to liquidity or the cost of its short-term borrowings.
Fitch Ratings Service announced on February 14, 2003 it was assigning an initial
rating to Progress Energy's senior unsecured debt of BBB-. No short-term rating
was assigned. Fitch also announced that it was downgrading the ratings of
Florida Power and CP&L. The ratings outlook for the three entities is stable.
Florida Power's senior secured rating was changed to A- from AA- and its senior
unsecured rating was changed to BBB+ from A+. Florida Power's short-term rating
was changed to F-2 from F-1+. CP&L's senior secured rating was changed to A-
from A+ and its senior unsecured rating was changed to BBB+ from A. CP&L's
short-term rating was changed to F-2 from F-1.
Interest Rate Derivatives
Progress Energy uses interest rate derivative instruments to manage the fixed
and variable rate debt components of its debt portfolio. The Company's long-term
objective is to maintain a debt portfolio mix of approximately 30% variable rate
debt, with the balance being fixed rate. As of December 31, 2002, Progress
Energy's variable rate and fixed rate debt comprised 18% and 82%, respectively,
including the effects of interest rate derivatives.
During March, April and May 2002, Progress Energy converted $1.0 billion of
fixed rate debt into variable rate debt by executing interest rate derivative
agreements with a group of five banks. Under the terms of the agreements, which
were scheduled to mature in 2006 and 2007 and coincide with the maturity dates
of the related debt issuances, Progress Energy received a fixed rate and paid a
floating rate based on three-month LIBOR. These instruments were designated as
fair value hedges for accounting purposes. In June 2002, Progress Energy
terminated these agreements. The terminations resulted in a $21.2 million
deferred hedging gain reflected in long-term debt, which will be amortized and
recorded as a reduction to interest expense over the life of the related debt
issuances.
In August 2002, Progress Energy converted $800 million of fixed rate debt into
variable rate debt by executing interest rate derivative agreements with a group
of four banks. Under the terms of the agreements, which were scheduled to mature
in 2006 and coincide with the maturity date of the related debt issuance,
Progress Energy received a fixed rate and paid a floating rate based on
three-month LIBOR. These instruments were designated as fair value hedges for
accounting purposes. In November 2002, Progress Energy terminated these
agreements. The terminations resulted in a $14 million deferred hedging gain
reflected in long-term debt, which will be amortized and recorded as a reduction
to interest expense over the life of the related debt issuance.
In December 2002, Progress Energy converted $350 million of fixed rate debt into
variable rate debt by executing interest rate derivative agreements with a group
of two banks. Under the terms of the agreements, which are scheduled to mature
in 2007 and coincide with the maturity date of the related debt issuance,
Progress Energy receives a fixed rate and pays a floating rate based on
three-month LIBOR. These instruments are designated as fair value hedges for
accounting purposes. At December 31, 2002, the value of these derivatives was a
$5.2 million asset position.
In December 2002, Florida Power entered into a Treasury Rate Lock agreement,
with a notional amount of $35 million, to hedge the interest rate risk on an
anticipated debt issuance. At December 31, 2002, the value of this hedge was a
$0.5 million liability position. In January 2003, Florida Power entered into a
Treasury Rate Lock agreement, with a notional amount of $20 million, to hedge
the interest rate risk on an anticipated debt issuance. These contracts are
designated as cash flow hedges for accounting purposes.
20
In January 2003, Progress Energy converted $500 million of fixed rate debt into
variable rate by executing interest rate derivative contracts, bringing its
variable rate percentage to 22.7%. Under the terms of the agreements, Progress
Energy will receive a fixed rate and will pay a floating rate based on
three-month LIBOR. These instruments were designated as fair value hedges for
accounting purposes.
Progress Genco Ventures, LLC has a floating rate credit facility that requires,
as part of the loan terms, a cash flow hedge against floating interest rate
exposure. In order to satisfy this requirement, Progress Genco Ventures, LLC
entered into a series of interest rate collars during 2002 with notional amounts
up to a maximum of $195 million and a final maturity date of March 20, 2007. At
December 31, 2002, the value of this hedge was a $12.3 million liability
position. See Note 16 to the Progress Energy consolidated financial statements
for further discussion of interest rate derivatives.
Future Commitments
The following tables reflect Progress Energy's contractual cash obligations and
other commercial commitments in the respective periods in which they are due.
(in millions)
- --------------------------------------------------------------------------------------------------------------------
Contractual Cash Total Amounts
Obligations Committed 2003 2004 2005 2006 2007 Thereafter
- --------------------------------------------------------------------------------------------------------------------
Long-term debt $ 10,082 $ 275 $ 869 $ 355 $ 909 $ 899 $ 6,775
Capital lease 45 3 3 3 3 3 30
obligations
Operating leases 293 76 59 35 25 20 78
Fuel 5,439 1,681 1,070 914 908 851 15
Purchased power 7,148 396 405 418 406 415 5,108
- --------------------------------------------------------------------------------------------------------------------
Total $ 23,007 $ 2,431 $ 2,406 $ 1,725 $ 2,251 $ 2,188 $ 12,006
Other Commercial Total Amounts
Commitments Committed 2003 2004 2005 2006 2007 Thereafter
- --------------------------------------------------------------------------------------------------------------------
Standby letters of $ 48 $ 48 $ - $ - $ - $ - $ -
credit
Guarantees and 569 52 41 30 20 19 407
other commitments
- --------------------------------------------------------------------------------------------------------------------
Total $ 617 $ 100 $ 41 $ 30 $ 20 $ 19 $ 407
Information on the Company's contractual obligations at December 31, 2002 is
included in the notes to the Progress Energy consolidated financial statements.
Future debt maturities and lease obligations are included in Note 8 and Note 12
to the Progress Energy consolidated financial statements, respectively. The
Company's fuel and purchased power obligations are included in Note 24A and Note
24B to the Progress Energy consolidated financial statements. The Company's
guarantees and other commitments are included in Note 24C to the Progress Energy
consolidated financial statements.
FUTURE OUTLOOK
The results of continuing operations for the past three years are not
necessarily indicative of future earnings potential. The level of Progress
Energy's future earnings depends on numerous factors. See SAFE HARBOR FOR
FORWARD-LOOKING STATEMENTS for a discussion of factors to be considered with
regard to forward-looking statements.
Regulatory issues facing Progress Energy are discussed in the "Current
Regulatory Environment" discussion under OTHER MATTERS below.
General Strategy
Progress Energy is an integrated energy company, with primary focus on the
end-use electricity market. This focus includes the generation, transmission and
distribution of electricity in both regulated and competitive markets. This
model includes the operations of the regulated utilities, CP&L and Florida Power
and the competitive generation and fuels businesses of Progress Ventures.
21
Regulated Utilities
The regulated utility operations of CP&L and Florida Power include the
transmission and distribution of over 20,350 megawatts of generation capacity
within the traditional service areas. Additional generation capacity and
capacity uprates are planned to serve the growth expected in the Company's
service territories and to increase capacity reserve margins at the electric
utilities. CP&L and Florida Power will continue to grow their customer bases and
focus on value-added services and technologies to enhance customer
relationships. These companies will focus on achieving top quartile results for
customer satisfaction, operational excellence and cost control (expense and
capital).
Progress Ventures
The competitive energy businesses of Progress Ventures include natural gas
exploration and production; coal fuel extraction, manufacturing and delivery,
which includes synthetic fuels operations; nonregulated generation; and energy
marketing and limited trading activities on behalf of its nonregulated plants.
Progress Ventures is scheduled to complete the remaining approximate 1,545
megawatts of nonregulated generation in 2003 for a total of 3,100 megawatts of
nonregulated generation in its portfolio by the end of 2003. Progress Ventures
is actively marketing this additional generation to serve demand in the
Southeast.
Progress Energy expects the wholesale electric energy market to remain soft for
at least the next several years. Through its Progress Ventures' business, the
Company will continue to search for opportunities to secure long-term contracts
with load serving entities. Future expansion of the nonregulated generating
portfolio, if it occurs, will depend upon achieving confidence in profitable
long-term sales from acquired assets. In the meantime, Progress Ventures will
continue to develop its natural gas production asset base both as an economic
hedge for nonregulated generation and as a profitable business in its own right.
Also, Progress Ventures will continue to leverage its coal blending, storage and
transportation assets in the Ohio River Valley area.
Diversified Subsidiaries
Progress Energy plans to divest its Progress Rail subsidiary at an opportune
time. The Company expects to accomplish the divestiture within the next three
years.
Progress Energy expects its Progress Telecom subsidiary to break even in 2003
and to fund its capital needs from internally generated funds. The Company is
open to opportunities for divestiture or business combination, but it does not
see this as a high probability due to ongoing difficulty in the overall
telecommunications industry.
Financial Strategy and Expectations
Progress Energy is focused on strengthening its balance sheet. The Company has
implemented a deleveraging plan through the use of asset sales and equity
issuances through direct stock purchases and the Company's employee benefit
plans. This plan also includes the issuance of equity to fund strategic
acquisitions and controlled capital spending. The Company expects its ratio of
total debt to total capitalization to decline from year to year.
Progress Energy's Board of Directors reviews its dividend policy each year. In
2002, the Company increased the dividend for the 15th consecutive year. Progress
Energy has paid quarterly cash dividends on its common stock without
interruption since 1947.
OTHER MATTERS
Progress Ventures - Generation Acquisition
During February 2002, PVI completed the acquisition of two electric generating
projects totaling nearly 1,100 megawatts in Georgia from LG&E for a total cash
purchase price of approximately $350 million including direct transaction costs.
The two projects consist of 1) the Walton project in Monroe, Georgia, a 460 MW
natural gas-fired plant placed in service in June 2001 and 2) the Washington
project in Washington County, Georgia, a planned 600 MW natural gas-fired plant
expected to be operational by June 2003. The transaction included a power
purchase agreement with LG&E Marketing for both projects through December 31,
2004. In addition, there is a project management and completion agreement
whereby LG&E has agreed to manage the completion of the Washington site
construction for PVI in exchange for cash consideration of $181 million. The
estimated costs to complete the Washington project as of December 31, 2002 are
approximately $57.8 million.
22
Progress Ventures - Fuel Acquisition
On April 26, 2002, Progress Energy finalized the acquisition of Westchester Gas
Company, which includes approximately 215 producing natural gas wells, 52 miles
of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate
purchase price of approximately $153 million consisted of cash consideration of
approximately $22 million and the issuance of 2.5 million shares of Progress
Energy common stock valued at approximately $129 million. The purchase price
included approximately $1.7 million of direct transaction costs. The properties
are located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border. This transaction added 140 billion cubic feet (Bcf) of gas reserves to
PVI's growing energy portfolio.
Current Regulatory Environment
General
The Company's electric and gas utility operations in North Carolina, South
Carolina and Florida are regulated by the North Carolina Utility Commission
(NCUC), the Public Service Commission of South Carolina (SCPSC) and the Florida
Public Service Commission (FPSC), respectively. The electric businesses are also
subject to regulation by the Federal Energy Regulatory Commission (FERC), the
U.S. Nuclear Regulatory Commission (NRC) and other federal and state agencies
common to the utility business. In addition, the Company is subject to SEC
regulation as a registered holding company under PUHCA. As a result of
regulation, many of the fundamental business decisions, as well as the rate of
return the electric utilities and the gas utility are permitted to earn, are
subject to the approval of governmental agencies.
Electric Industry Restructuring
CP&L and Florida Power continue to monitor progress toward a more competitive
environment and have actively participated in regulatory reform deliberations in
North Carolina, South Carolina and Florida. Movement toward deregulation in
these states has been affected by recent developments, including developments
related to deregulation of the electric industry in California and other states.
o North Carolina. The Company expects the North Carolina General
Assembly will continue to monitor the experiences of states that have
implemented electric restructuring legislation.
o South Carolina. The Company expects the South Carolina General
Assembly will continue to monitor the experiences of states that have
implemented electric restructuring legislation.
o Florida. On December 11, 2001, the Florida 2020 Study Commission
issued its final report to the Florida Legislature. The report covered
a number of issues with recommendations in the areas of wholesale
competition and reliability, efficiency, transmission infrastructure,
environmental issues and new technologies. A key recommendation
related to wholesale competition and reliability permits the transfer
or sale of existing generation at book value and on a plant-by-plant
basis, with the sale and transfer being at the discretion of the
investor-owned utility. The Florida Legislature did not take any
action on the proposed outline or final report during the 2001 or 2002
legislative session.
The Company cannot anticipate when, or if, any of these states will move to
increase competition in the electric industry.
Florida Retail Rate Proceeding
On March 27, 2002, the parties in Florida Power's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The Agreement
is generally effective from May 1, 2002 through December 31, 2005; provided,
however, that if Florida Power's base rate earnings fall below a 10% return on
equity, Florida Power may petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues from
the sale of electricity by an annual amount of $125 million. The Agreement also
provides that Florida Power will operate under a Revenue Sharing Incentive Plan
(the Plan) through 2005, and thereafter until terminated by the FPSC, that
establishes annual revenue caps and sharing thresholds. The Plan provides that
retail base rate revenues between the sharing thresholds and the retail base
rate revenue caps will be divided into two shares - a 1/3 share to be received
by Florida Power's shareholders, and a 2/3 share to be refunded to Florida
Power's retail customers; provided, however, that for the year 2002 only, the
refund to customers will be limited to 67.1% of the 2/3 customer share. The
retail base rate revenue sharing threshold amounts for 2002 were $1,296 million
and will increase $37 million each year thereafter. The Plan also provides that
all retail base rate revenues above the retail base rate revenue caps
established for each year will be refunded to retail customers on an annual
basis. For 2002, the refund to customers was limited to 67.1% of the retail base
rate revenues that exceed the 2002 cap. The retail base revenue cap for 2002 was
$1,356 million and will increase $37 million each year thereafter. Any amounts
above the retail base revenue caps will be refunded 100% to customers. As of
December 31, 2002, $4.7 million was accrued and will be refunded to customers by
March 2003.
23
Per the Agreement, Florida Power was required to refund to customers $35 million
of revenues Florida Power collected during the interim period since March 13,
2001. This one-time retroactive revenue refund was recorded in the first quarter
of 2002 and was returned to retail customers over an eight-month period ended
December 31, 2002. Any additional refunds under the Agreement are recorded when
they become probable.
See Note 15B to the Progress Energy consolidated financial statements for
additional information on the Agreement.
North Carolina Clean Air Legislation
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from coal-fired power plants. Progress Energy expects its capital costs
to meet these emission targets to be approximately $813 million by 2013. CP&L
currently has approximately 5,100 MW of coal-fired generation in North Carolina
that is affected by this legislation. The legislation requires the emissions
reductions to be completed in phases by 2013, and applies to each utility's
total system rather than setting requirements for individual power plants. The
legislation also freezes the utilities' base rates for five years unless there
are extraordinary events beyond the control of the utilities or unless the
utilities persistently earn a return substantially in excess of the rate of
return established and found reasonable by the NCUC in the utilities' last
general rate case. Further, the legislation allows the utilities to recover from
their retail customers the projected capital costs during the first seven years
of the 10-year compliance period beginning on January 1, 2003. The utilities
must recover at least 70% of their projected capital costs during the five-year
rate freeze period. Pursuant to the new law, CP&L entered into an agreement with
the state of North Carolina to transfer to the state all future emissions
allowances it generates from over-complying with the new federal emission limits
when these units are completed. The new law also requires the state to undertake
a study of mercury and carbon dioxide emissions in North Carolina. Progress
Energy cannot predict the future regulatory interpretation, implementation or
impact of this new law.
Other Retail Rate Matters
See Note 15C to the Progress Energy consolidated financial statements for
additional information on the Company's other retail rate matters.
Regional Transmission Organizations and Standard Market Design
Florida Power
In early 2000 FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions that
RTOs must meet, including independent transmission service. As a result of Order
2000, Florida Power, along with Florida Power & Light Company and Tampa Electric
Company, filed with FERC, in October 2000, an application for approval of a Grid
Florida RTO. On March 28, 2001, FERC issued an order provisionally approving
GridFlorida. However, in July 2001, FERC issued orders recommending that
companies in the Southeast engage in a mediation to develop a plan for a single
RTO for the Southeast. Florida Power participated in the mediation. FERC has not
issued an order specifically on this mediation. FERC held a discussion on the
mediation report on November 24, 2001. In January 2002, FERC stated that it
would issue orders on the RTO formations for the Southeast during the first half
of 2002 after the development of a standardized market design for the wholesale
electricity market. On July 31, 2002, FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity Market Design (SMD
NOPR). The proposed rules set forth in the SMD NOPR would require, among other
things, that 1) all transmission owning utilities transfer control of their
transmission facilities to an independent third party; 2) transmission service
to bundled retail customers be provided under the FERC-regulated transmission
tariff, rather than state-mandated terms and conditions; 3) new terms and
conditions for transmission service be adopted nationwide, including new
provisions for pricing transmission in the event of transmission congestion; 4)
new energy markets be established for the buying and selling of electric energy;
and 5) load serving entities be required to meet minimum criteria for generating
reserves. If adopted as proposed, the rules set forth in the SMD NOPR would
materially alter the manner in which transmission and generation services are
provided and paid for. Florida Power, as a subsidiary of Progress Energy, filed
comments on November 15, 2002 and supplement comments on January 10, 2003. On
January 15, 2003, FERC announced the issuance of a White Paper on SMD to be
released in April 2003. Florida Power, as a subsidiary of Progress Energy, plans
to file comments on the White Paper. FERC has also indicated that it expects to
issue final rules during the summer 2003. The Company cannot predict the outcome
of these matters or the effect that they may have on the GridFlorida proceedings
currently ongoing before the FERC.
24
On May 16, 2001, the FPSC initiated dockets to review the prudence of the
GridFlorida applicants' decision to form and participate in the GridFlorida RTO.
On October 15, 2002 the Florida Public Service Commission (FPSC) abated its
proceedings regarding its review of the proposed GridFlorida RTO. The
GridFlorida RTO proposal includes the formation of a not-for-profit Independent
System Operator (ISO) by the joint Applicants - Florida Power Corporation,
Florida Power & Light Company, and Tampa Electric Company. Participation is
expected from many of the other transmission owners in the state of Florida. The
FPSC previously found the Applicants were prudent in proactively forming
GridFlorida but ordered the Applicants to modify their proposal. The
modifications include but are not limited to addressing 1) pricing structure
that recognizes the FPSC's jurisdiction over retail transmission rates, 2)
pricing/rate structure of long term transmission contracts, 3) elimination of
pancaking of short-term transmission revenues, 4) cost recovery of incremental
costs imposed on the applicants, 5) demarcation dates for new facilities and
long-term transmission contracts, and 6) market design. The FPSC action to abate
the proceedings came in response to the Florida Office of Public Counsel's
appeal before the state Supreme Court requesting review of the FPSC's order
approving the transfer of operational control of electric transmission assets to
an RTO under the jurisdiction of the FERC. It is unknown what the outcome of
this appeal will be at this time. It is unknown what impact the future
proceedings in regard to GridFlorida will have on the Company's earnings,
revenues or prices.
CP&L
In early 2000 FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions that
RTOs must meet, including independent transmission service. In October 2000, as
a result of Order 2000, CP&L, along with Duke Energy Corporation and South
Carolina Electric & Gas Company, filed an application with FERC for approval of
a GridSouth RTO. On July 12, 2001, FERC issued an order provisionally approving
GridSouth. However, in July 2001, FERC issued orders recommending that companies
in the Southeast engage in a mediation to develop a plan for a single RTO for
the Southeast. CP&L participated in the mediation. FERC has not issued an order
specifically on this mediation. FERC held a discussion on the mediation report
on November 24, 2001. In January 2002, FERC stated that it would issue orders on
the RTO formations for the Southeast during the first half of 2002 after the
development of a standardized market design for the wholesale electricity
market. On July 31, 2002, FERC issued its Notice of Proposed Rulemaking in
Docket No. RM01-12-000. Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market Design (SMD NOPR). The
proposed rules set forth in the SMD NOPR would require, among other things, that
1) all transmission owning utilities transfer control of their transmission
facilities to an independent third party; 2) transmission service to bundled
retail customers be provided under the FERC-regulated transmission tariff,
rather than state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load serving
entities be required to meet minimum criteria for generating reserves. If
adopted as proposed, the rules set forth in the SMD NOPR would materially alter
the manner in which transmission and generation services are provided and paid
for. CP&L, as a subsidiary of Progress Energy, filed comments on November 15,
2002 and supplement comments on January 10, 2003. On January 15, 2003, FERC
announced the issuance of a White Paper on SMD to be released in April 2003.
CP&L, as a subsidiary of Progress Energy, plans to file comments on the White
Paper. FERC has also indicated that it expects to issue final rules during the
summer 2003. The Company cannot predict the outcome of these matters or the
effect that they may have on the GridSouth proceedings currently ongoing before
FERC.
CP&L applied to the NCUC and the SCPSC for permission to transfer operational
control of its transmission assets to GridSouth. On June 21, 2001, the Public
Staff of the NCUC filed a motion asking the NCUC to hold the GridSouth docket in
abeyance until the U.S. Supreme Court had ruled on the appeal of FERC's Order
No. 888. That appeal addresses the scope of FERC's jurisdiction over
transmission service used to serve retail customers. The appeal of Order No. 888
was heard by the Court on October 3, 2001, and its decision affirmed FERC's
order. The NCUC issued an order holding that CP&L's and Duke Energy
Corporation's petition to transfer operational control of their transmission
assets to GridSouth shall be held in abeyance pending further order. In February
2002, CP&L and the other GridSouth applicants withdrew the GridSouth application
from the NCUC and SCPSC for purposes of making certain revisions to the
GridSouth proposal. The Company has $28.4 million invested in GridSouth at
December 31, 2002. It is unknown what impact the future proceedings in regard to
GridSouth will have on the Company's earnings, revenues or prices.
25
Franchise Litigation
Six cities, with a total of approximately 49,000 customers, have sued Florida
Power in various circuit courts in Florida. The lawsuits principally seek 1) a
declaratory judgment that the cities have the right to purchase Florida Power's
electric distribution system located within the municipal boundaries of the
cities, 2) a declaratory judgment that the value of the distribution system must
be determined through arbitration, and 3) injunctive relief requiring Florida
Power to continue to collect from Florida Power's customers and remit to the
cities, franchise fees during the pending litigation, and as long as Florida
Power continues to occupy the cities' rights-of-way to provide electric service,
notwithstanding the expiration of the franchise ordinances under which Florida
Power had agreed to collect such fees. Five circuit courts have entered orders
requiring arbitration to establish the purchase price of Florida Power's
electric distribution system within five cities. Two appellate courts have
upheld those circuit court decisions and authorized cities to determine the
value of Florida Power's electric distribution system within the cities through
arbitration. To date, no city has attempted to actually exercise the right to
purchase any portion of Florida Power's electric distribution system.
Arbitration in one of the cases was held in August 2002 and an award was issued
in October 2002 setting the value of Florida Power's distribution system within
one city at approximately $22 million. At this time, whether and when there will
be further proceedings following this award cannot be determined. Additional
arbitrations have been scheduled to occur in the first and second quarters of
2003.
As part of the above litigation, two appellate courts have also reached opposite
conclusions regarding whether Florida Power must continue to collect from its
customers and remit to the cities "franchise fees" under the expired franchise
ordinances. Florida Power has filed an appeal with the Florida Supreme Court to
resolve the conflict between the two appellate courts. The Florida Supreme Court
has issued an order setting a briefing schedule and reserving ruling on
accepting jurisdiction. On January 12, 2003, Florida Power served its Initial
Brief in the Supreme Court and its request for oral argument. Three amicus
curiae also filed motions seeking leave to participate in support of Florida
Power's position and filed amicus briefs. No oral argument has yet been set. The
Company cannot predict the outcome of these matters at this time.
Nuclear
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. See Note 1H to the
Progress Energy consolidated financial statements for a discussion of the
Company's nuclear decommissioning costs.
Spent Fuel Storage
On December 21, 2000, CP&L received permission from the NRC to increase its
storage capacity for spent fuel rods in Wake County, North Carolina. The NRC's
decision came two years after CP&L asked for permission to open two unused
storage pools at the Shearon Harris Nuclear Plant (Harris Plant). The approval
meant that CP&L was able to complete cooling systems and begin installing
storage racks in its third and fourth storage pools at the Harris Plant.
Pressurized Water Reactors
On March 18, 2002, the NRC sent a bulletin to companies that hold licenses for
pressurized water reactors (PWRs) requiring information on the structural
integrity of the reactor vessel head and a basis for concluding that the vessel
head will continue to perform its function as a coolant pressure boundary. The
Company filed responses as required. Inspections of the vessel heads at the
Company's PWR plants have been performed during previous outages. In October
2001 at the Crystal River Plant (CR3), one nozzle was found to have a crack and
was repaired; however, no degradation of the reactor vessel head was identified.
Current plans are to replace the vessel head at CR3 during its next regularly
scheduled refueling outage in 2003. At the Robinson Plant, an inspection was
completed in April 2001 and no penetration nozzle cracking was identified and
there was no degradation of the reactor vessel head. At the Harris Plant,
sufficient inspections were completed during the last refueling outage in the
fourth quarter of 2001 to conclude there is no degradation of the reactor vessel
head. The Company's Brunswick Plant has a different design and is not affected
by the issue.
On August 9, 2002, the NRC issued an additional bulletin dealing with head
leakage due to cracks near the control rod nozzles. The NRC has asked licensees
to commit to high inspection standards to ensure the more susceptible plants
have no cracks. The Robinson Plant is in this category and had a refueling
outage in October 2002. The Company completed a series of examinations in
October 2002 of the entire reactor pressure vessel head and found no indications
of control rod drive mechanism cracking and no corrosion of the head itself.
During the outage, a boric acid leakage walkdown of the reactor coolant pressure
boundary was also completed and no corrosion was found. For CR3, the Company has
responded to the NRC that previous inspections are sufficient until the reactor
head is replaced in the fall of 2003. For the Harris Plant, the Company does not
plan further inspections until its next regularly scheduled outage in spring of
2003.
26
In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated penetration nozzles at PWRs.
The Company is currently reviewing the Order, but based on the inspections and
replacement plan outlined above, no adverse impact is anticipated.
Security
On February 25, 2002, the NRC issued an interim compensatory measure with regard
to security at nuclear plants. This order formalized many of the security
enhancements made at the Company's nuclear plants since September 2001. This
order includes additional restrictions on access, increased security presence
and closer coordination with the Company's partners in intelligence, military,
law enforcement and emergency response at the federal, state and local levels.
The Company completed the requirements by the established deadlines and expects
the NRC to perform an inspection for compliance in the near future.
In addition, in January 2003 the NRC issued a final order with regards to access
control. This order requires the Company to enhance its current access control
program by January 7, 2004. The Company expects that it will be in full
compliance with the order by the established deadline.
As the NRC, other governmental entities, and the industry continue to consider
security issues, it is possible that more extensive security plans could be
required.
Synthetic Fuels Tax Credits
Progress Energy, through the Progress Ventures business unit, produces synthetic
fuel from coal fines. The production and sale of the synthetic fuel qualifies
for tax credits under Section 29 of the Internal Revenue Code (Section 29) if
certain requirements are satisfied, including a requirement that the synthetic
fuel differs significantly in chemical composition from the feedstock used to
produce such synthetic fuel. Any synthetic fuel tax credit amounts not utilized
are carried forward indefinitely and are included in deferred taxes on the
accompanying Consolidated Balance Sheet. See Note 20 to the Progress Energy
consolidated financial statements. All of Progress Energy's synthetic fuel
facilities have received private letter rulings from the IRS with respect to
their operations. These tax credits are subject to review by the IRS, and if
Progress Energy fails to prevail through the administrative 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. Tax credits for
the 12 months ended December 31, 2002 and 2001, were $291 million and $349
million, respectively. Total Section 29 credits generated to date (including FPC
prior to its acquisition by the Company) are approximately $897.2 million.
One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P., from
which the Company (and FPC prior to its acquisition by the Company) has been
allocated approximately $251 million in tax credits to date, is being audited by
the IRS. The audit of Colona was expected. The Company is audited regularly in
the normal course of business, as are most similarly situated companies. In
September 2002, all of Progress Energy's majority-owned synthetic fuel entities,
including Colona, were accepted into the IRS Pre-Filing Agreement (PFA) program.
The PFA program allows taxpayers to voluntarily accelerate the IRS exam process
in order to seek resolution of specific issues. Either the Company or the IRS
can withdraw from the program at any time, and issues not resolved through the
program may proceed to the next level of the IRS exam process. While the
ultimate outcome is uncertain, the Company believes that participation in the
PFA program will likely shorten the tax exam process. In management's opinion,
Progress Energy is complying with the private letter rulings and all the
necessary requirements to be allowed such credits under Section 29 and believes
it is likely, although it cannot provide certainty, that it will prevail if
challenged by the IRS on any credits taken. The current Section 29 tax credit
program expires in 2007.
The Company has retained an advisor to assist in selling an interest in one or
more synthetic fuel entities. The Company is pursuing the sale of a portion of
its synthetic fuel production capacity that is underutilized due to limits on
the amount of credits that can be generated and utilized by the Company. The
Company would expect to retain an ownership interest and to operate any sold
facility for a management fee. The final outcome and timing of these discussions
is uncertain and the Company cannot predict the outcome of this matter.
Environmental Matters
The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other environmental
matters. These environmental matters are discussed in detail in Note 24 to the
Progress Energy consolidated financial statements. This discussion identifies
specific environmental issues, the status of the issues, accruals associated
with issue resolutions, and the associated exposures to the Company.
27
New Accounting Standards
See Note 1U and Note 6 to the Progress Energy consolidated financial statements
for a discussion of the impact of new accounting standards.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Certain market risks are inherent in the Company's financial
instruments, which arise from transactions entered into in the normal course of
business. The Company's primary exposures are changes in interest rates with
respect to its long-term debt and commercial paper, and fluctuations in the
return on marketable securities with respect to its nuclear decommissioning
trust funds. The Company manages its market risk in accordance with its
established risk management policies, which may include entering into various
derivative transactions.
These financial instruments are held for purposes other than trading. The fair
value of the Company's open trading positions was less than a $0.4 million
liability position at December 31, 2002. The risks discussed below do not
include the price risks associated with nonfinancial instrument transactions and
positions associated with the Company's operations, such as purchase and sales
commitments and inventory.
Interest Rate Risk
The Company manages its interest rate risks through the use of a combination of
fixed and variable rate debt. Variable rate debt has rates that adjust in
periods ranging from daily to monthly. Interest rate derivative instruments may
be used to adjust interest rate exposures and to protect against adverse
movements in rates.
The following tables provide information as of December 31, 2002 and 2001, about
the Company's interest rate risk sensitive instruments. The tables present
principal cash flows and weighted-average interest rates by expected maturity
dates for the fixed and variable rate long-term debt, FPC obligated mandatorily
redeemable securities of trust, and other short-term indebtedness. The tables
also include estimates of the fair value of the Company's interest rate risk
sensitive instruments based on quoted market prices for these or similar issues.
For interest-rate swaps and interest-rate forward contracts, the tables present
notional amounts and weighted-average interest rates by contractual maturity
dates. Notional amounts are used to calculate the contractual cash flows to be
exchanged under the interest-rate swaps and the settlement amounts under the
interest-rate forward contracts. See "Interest Rate Derivatives" under LIQUIDITY
AND CAPITAL RESOURCES above for more information on interest rate derivatives.
28
December 31, 2002 Fair Value
December 31,
(Dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002
- --------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 275 $ 869 $ 355 $ 909 $ 674 $ 5,614 $ 8,696 $ 9,584
Average interest rate 6.42% 6.66% 7.38% 6.78% 6.41% 6.90% 6.83%
Variable rate long-term debt - - - - $ 225 $ 861 $ 1,086 $ 1,087
Average interest rate - - - - 0.03% 1.24% 1.61% -
Mandatorily redeemable
securities of trust - - - - - $ 300 $ 300 $ 303
Interest rate 7.10% 7.10% -
Interest-rate swaps:
Pay fixed/receive variable(a) - - - - $ 350 - $ 350 $ 5.2
Interest rate forward
contracts(b) $ 35 - - - - - $ 35 $ (0.5)
Interest rate collars(c) $ 195 $ 195 $ (12.3)
(a) Receives floating rate based on three-month LIBOR and pays fixed rate of
7.17%. Designated as hedge of $350 million of fixed rate debt.
(b) Treasury Rate Lock agreement on $35 million designated as fair value hedge
of anticipated debt issuance.
(c) Interest rate collars on $195 million notional. Designated as hedge of
variable rate interest.
December 31, 2001 Fair Value
December 31,
(Dollars in millions) 2002 2003 2004 2005 2006 Thereafter Total 2001
- --------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 188 $ 283 $ 869 $ 348 $ 909 $ 5,379 $ 7,976 $ 8,322
Average interest rate 6.38% 6.42% 6.67% 7.39% 6.78% 6.97% 6.90% -
Variable rate long-term debt - - - - - $ 620 $ 620 $ 621
Average interest rate - - - - - 1.58% 1.58% -
Extendible notes $ 500 - - - - - $ 500 $ 500
Average interest rate -
variable rate 2.83% - - - - - 2.83% -
FPC mandatorily redeemable
securities of trust - - - - - $ 300 $ 300 $ 291
Fixed rate - 7.10% 7.10% -
Interest-rate swaps:
Pay fixed/receive variable (a) $ 500 - - - - - $ 500 $ (18.5)
(a) Receives floating rate based on three-month LIBOR and pays fixed rate of
7.17%. Designated as a hedge of interest payments on $500 million of
extendible notes.
Marketable Securities Price Risk
The Company's electric utility subsidiaries maintain trust funds, pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents, which
are exposed to price fluctuations in equity markets and to changes in interest
rates. The fair value of these funds was $796.8 million and $822.8 million at
December 31, 2002 and 2001, respectively. The Company actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, target allocation
percentages for various asset classes. The accounting for nuclear
decommissioning recognizes that the Company's regulated electric rates provide
for recovery of these costs net of any trust fund earnings and, therefore,
fluctuations in trust fund marketable security returns do not affect the
earnings of the Company.
Contingent Value Obligations (CVOs) Market Value Risk
In connection with the acquisition of FPC, 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, are based on the net after-tax cash flows
the facilities generate. These CVOs are recorded at fair value and unrealized
gains and losses from changes in fair value are recognized in earnings. At
December 31, 2002 and 2001, the fair value of these CVOs was $13.8 million and
$41.9 million, respectively. A hypothetical 10% decrease in the December 31,
2002 market price would result in a $1.4 million decrease in the fair value of
the CVOs.
29
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This combined report contains forward-looking statements within the meaning of
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995. The matters discussed throughout this Report that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.
In addition, examples of forward-looking statements discussed in this Annual
Report include, but are not limited to, statements under the following headings:
1) "Liquidity and Capital Resources" about operating cash flows, estimated
capital requirements through the year 2005 and future financing plans, 2)
"Future Outlook" about Progress Energy's future earnings potential, and 3)
"Other Matters" about the effects of new environmental regulations, nuclear
decommissioning costs and the effect of electric utility industry restructuring.
Any forward-looking statement speaks only as of the date on which such statement
is made, and Progress Energy (the Company) undertakes no obligation to update
any forward-looking statement or statements to reflect events or circumstances
after the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; the impact of recent events in the
energy markets that have increased the level of public and regulatory scrutiny
in the energy industry and in the capital markets; deregulation or restructuring
in the electric industry that may result in increased competition and
unrecovered (stranded) costs; the uncertainty regarding the timing, creation and
structure of regional transmission organizations; weather conditions that
directly influence the demand for electricity and natural gas; recurring
seasonal fluctuations in demand for electricity and natural gas; fluctuations in
the price of energy commodities and purchased power; economic fluctuations and
the corresponding impact on the Company's commercial and industrial customers;
the ability of the Company's subsidiaries to pay upstream dividends or
distributions to it; the impact on the facilities and the businesses of the
Company from a terrorist attack; the inherent risks associated with the
operation of nuclear facilities, including environmental, health, regulatory and
financial risks; the ability to successfully access capital markets on favorable
terms; the impact that increases in leverage may have on the Company; the
ability of the Company to maintain its current credit ratings; the impact of
derivative contracts used in the normal course of business by the Company; the
Company's continued ability to use Section 29 tax credits related to its coal
and synthetic fuels businesses; the continued depressed state of the
telecommunications industry and the Company's ability to realize future returns
from Progress Telecom and Caronet, Inc.; the Company's ability to successfully
integrate newly acquired businesses, including Westchester Gas Company, into its
operations as quickly or as profitably as expected; the Company's ability to
successfully complete the sale of North Carolina Natural Gas and apply the
proceeds therefrom to reduce outstanding indebtedness; the Company's ability to
manage the risks involved with the construction and operation of its
nonregulated plants, including construction delays, dependence on third parties
and related counter-party risks, and a lack of operating history; the Company's
ability to manage the risks associated with its energy marketing and trading
operations; and unanticipated changes in operating expenses and capital
expenditures. Many of these risks similarly impact the Company's subsidiaries.
These and other risk factors are detailed from time to time in Progress Energy's
SEC reports, particularly Progress Energy's Form 8-K filed November 7, 2002 and
any further amendments thereto. All such factors are difficult to predict,
contain uncertainties that may materially affect actual results, and may be
beyond the control of Progress Energy. New factors emerge from time to time, and
it is not possible for management to predict all such factors, nor can it assess
the effect of each such factor on Progress Energy.
30
EXHIBIT 99.2
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 its subsidiaries as of December 31, 2002 and 2001, 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, 2002. 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 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, such financial statements present fairly, in all material
respects, the financial position of the Company and its subsidiaries at December
31, 2002 and 2001, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002, in conformity
with accounting principles generally accepted in the United States of America.
As discussed in Note 6 to the financial statements, in 2002 the Company changed
its method of accounting for goodwill to conform to Statement of Financial
Accounting Standards No. 142.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003
1
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
Years ended December 31
(In thousands except per share data) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 6,600,689 $ 6,556,561 $ 3,545,694
Diversified business 1,344,431 1,528,819 223,228
- ---------------------------------------------------------------------------------------------------------------
Total Operating Revenues 7,945,120 8,085,380 3,768,922
- ---------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 1,614,879 1,559,998 682,627
Purchased power 862,395 868,078 364,977
Operation and maintenance 1,361,189 1,210,750 792,164
Depreciation and amortization 820,279 1,067,073 735,353
Taxes other than on income 386,254 379,830 162,268
Diversified business
Cost of sales 1,433,626 1,422,890 81,376
Impairment of long-lived assets 363,822 42,852 -
Other 98,193 304,817 266,931
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 6,940,637 6,856,288 3,085,696
- ---------------------------------------------------------------------------------------------------------------
Operating Income 1,004,483 1,229,092 683,226
- ---------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 14,526 22,481 18,353
Impairment of investments (25,011) (164,183) -
Gain on sale of investment - - 200,000
Other, net 33,804 (28,439) 15,423
- ---------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 23,319 (170,141) 233,776
- ---------------------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 641,574 689,694 261,570
Allowance for borrowed funds used during construction (8,133) (16,801) (18,992)
- ---------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 633,441 672,893 242,578
- ---------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax 394,361 386,058 674,424
Income Tax Expense (Benefit) (157,808) (154,338) 196,502
- ---------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 552,169 540,396 477,922
Discontinued Operations, net of tax (23,783) 1,214 439
- ---------------------------------------------------------------------------------------------------------------
Net Income $ 528,386 $ 541,610 $ 478,361
- ---------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 217,247 204,683 157,169
- ---------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations $ 2.54 $ 2.64 $ 3.04
Discontinued Operations, net of tax (.11) .01 .00
Net Income 2.43 2.65 3.04
- ---------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations $ 2.53 $ 2.63 $ 3.03
Discontinued Operations, net of tax (.11) .01 .00
Net Income 2.42 2.64 3.03
- ---------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 2.195 $ 2.135 $ 2.075
- ---------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
2
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands except per share data) December 31
Assets 2002 2001
- ----------------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 20,152,787 $ 19,176,021
Accumulated depreciation (10,480,880) (9,936,514)
- ----------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 9,671,907 9,239,507
Held for future use 15,109 15,380
Construction work in progress 752,336 1,004,011
Nuclear fuel, net of amortization 216,882 262,869
- ----------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 10,656,234 10,521,767
- ----------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 61,358 53,708
Accounts receivable 737,369 779,286
Unbilled accounts receivable 225,011 199,593
Inventory 875,485 871,643
Deferred fuel cost 183,518 146,652
Assets of discontinued operations 490,429 552,458
Prepayments and other current assets 283,036 294,460
- ----------------------------------------------------------------------------------------------------------------------
Total Current Assets 2,856,206 2,897,800
- ----------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 393,215 463,837
Nuclear decommissioning trust funds 796,844 822,821
Diversified business property, net 1,884,271 1,072,123
Miscellaneous other property and investments 463,776 441,932
Goodwill 3,719,327 3,656,970
Prepaid pension costs 60,169 487,551
Other assets and deferred debits 522,662 525,900
- ----------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,840,264 7,471,134
- ----------------------------------------------------------------------------------------------------------------------
Total Assets $ 21,352,704 $ 20,890,701
- ----------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- ----------------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500,000,000 shares authorized, 237,992,513 and
218,725,352 shares issued and outstanding,
respectively $ 4,950,558 $ 4,121,194
Unearned restricted shares (950,180 and 674,511 shares, respectively) (21,454) (13,701)
Unearned ESOP shares (4,616,400 and 5,199,388 shares, respectively) (101,560) (114,385)
Accumulated other comprehensive loss (237,762) (32,180)
Retained earnings 2,087,227 2,042,605
- ----------------------------------------------------------------------------------------------------------------------
Total common stock equity 6,677,009 6,003,533
- ----------------------------------------------------------------------------------------------------------------------
Preferred stock of subsidiaries-not subject to mandatory redemption 92,831 92,831
Long-term debt 9,747,293 8,618,960
- ----------------------------------------------------------------------------------------------------------------------
Total capitalization 16,517,133 14,715,324
- ----------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 275,397 688,052
Accounts payable 756,287 760,116
Interest accrued 220,400 211,731
Dividends declared 132,232 117,857
Short-term obligations 694,850 942,314
Customer deposits 158,214 151,968
Liabilities of discontinued operations 124,767 162,917
Other current liabilities 372,161 403,868
- ----------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,734,308 3,438,823
- ----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 932,813 1,408,155
Accumulated deferred investment tax credits 206,221 224,688
Regulatory liabilities 119,766 291,789
Other liabilities and deferred credits 842,463 811,922
- ----------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,101,263 2,736,554
- ----------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 24)
- ----------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 21,352,704 $ 20,890,701
- ----------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
3
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
Years ended December 31
(In thousands) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 528,386 $ 541,610 $ 478,361
Adjustments to reconcile net income to net cash provided by operating activities:
Loss (income) from discontinued operations 23,783 (1,214) (439)
Impairment of long-lived assets and investments 388,833 208,983 -
Depreciation and amortization 1,099,128 1,266,162 846,984
Deferred income taxes (402,040) (367,330) (93,379)
Investment tax credit (18,467) (22,701) (17,942)
Gain on sale of investment - - (200,000)
Deferred fuel cost (credit) (36,866) 68,705 (81,604)
Net (increase) decrease in accounts receivable (45,172) 182,514 (34,754)
Net (increase) decrease in inventories (48,785) (298,733) 15,931
Net (increase) decrease in prepayments and other current assets (39,141) (20,797) 57,141
Net increase (decrease) in accounts payable 57,387 (162,940) 229,117
Net increase (decrease) in other current liabilities 56,356 123,297 (148,813)
Other 34,509 (94,806) (197,725)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,597,911 1,422,750 852,878
- ---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (1,174,220) (1,177,727) (853,584)
Diversified business property additions and acquisitions (934,910) (349,713) (157,510)
Nuclear fuel additions (80,573) (115,663) (59,752)
Acquisition of Florida Progress Corporation, net of cash - - (3,441,775)
Net proceeds from sale of assets and investment 42,825 53,010 200,000
Net contributions to nuclear decommissioning trust (18,502) (50,649) (32,391)
Investments in non-utility activities (27,030) (15,043) (89,351)
Other (19,424) - -
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (2,211,834) (1,655,785) (4,434,363)
- ---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net 687,000 488,290 -
Issuance of long-term debt, net 1,797,691 4,564,243 783,052
Net increase (decrease) in short-term indebtedness (247,464) (4,018,062) 3,782,071
Net increase (decrease) in cash provided by checks drawn in excess of bank balances 79 (45,372) 115,337
Retirement of long-term debt (1,157,286) (322,207) (710,373)
Dividends paid on common stock (479,981) (432,078) (368,004)
Other 21,482 (47,127) (66)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Financing Activities 621,521 187,687 3,602,017
- ---------------------------------------------------------------------------------------------------------------------------------
Cash Provided by (Used in) Discontinued Operations 52 (843) 525
- ---------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 7,650 (46,191) 21,057
Cash and Cash Equivalents at Beginning of Year 53,708 99,899 78,842
- ---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 61,358 $ 53,708 $ 99,899
- ---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 630,935 $ 588,127 $ 244,224
income taxes (net of refunds) $ 219,278 $ 127,427 $ 367,665
Noncash Activities
o On June 28, 2000, Caronet, Inc. 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.
o On November 30, 2000, the Company purchased all outstanding shares of
Florida Progress Corporation. In conjunction with the purchase, the Company
issued approximately $1.9 billion in common stock and $49.3 million in
contingent value obligations.
o On April 26, 2002, Progress Fuels Corporation, a subsidiary of the Company,
acquired 100% of Westchester Gas Company. In conjunction with the purchase,
the Company issued approximately $129.0 million in common stock.
See Notes to Consolidated Financial Statements
4
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES IN COMMON STOCK EQUITY
Unearned Accumulated Total
Unearned ESOP Other Common
(In thousands except share data) Common Stock Outstanding Restricted Common Comprehensive Retained Stock
Shares Amount Stock Stock Income (Loss) Earnings Equity
- -----------------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2000 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)
Reclassification adjustment for amounts
included in net income (net of tax of
$8,739) 13,647 13,647
Foreign currency translation and other (1,557) (1,557)
-----------
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
Net income 528,386 528,386
Change in net unrealized losses on cash
flow hedges (net of tax of $17,712) (27,920) (27,920)
Reclassification adjustment for amounts
included in net income (net of tax of
$10,480) 16,307 16,307
Foreign currency translation and other (1,584) (1,584)
Minimum pension liability adjustment
(net of tax of $120,903) (192,385) (192,385)
-----------
Comprehensive income 322,804
-----------
Issuance of shares 19,282,212 815,393 815,393
Purchase of restricted stock (16,197) (16,197)
Restricted stock expense recognition 7,709 7,709
Cancellation of restricted shares (15,051) (735) 735 -
Allocation of ESOP shares 14,706 12,825 27,531
Dividends ($2.195 per share) (483,764) (483,764)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 237,992,513 $ 4,950,558 $(21,454) $ (101,560) $ (237,762) $ 2,087,227 $6,677,009
===================================================================================================================================
See Notes to Consolidated Financial Statements
5
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In thousands except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter
- ---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues $1,787,302 $1,958,855 $2,277,040 $1,921,923
Operating income 241,981 305,288 200,221 256,993
Income from continuing operations 124,062 121,933 157,073 149,101
Net income 132,527 120,620 151,934 123,305
Common stock data:
Basic earnings per common share
Income from continuing operations 0.58 0.57 0.73 0.66
Net Income 0.62 0.56 0.70 0.55
Diluted earnings per common share
Income from continuing operations 0.58 0.56 0.72 0.66
Net Income 0.62 0.56 0.70 0.55
Dividends paid per common share 0.545 0.545 0.545 0.545
Market price per share - High 50.86 52.70 51.97 44.82
Low 43.01 47.91 36.54 32.84
- ---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues $1,755,839 $2,233,383 $2,265,223 $1,830,935
Operating income 295,611 288,898 455,475 189,108
Income (loss) from continuing operations 146,807 117,080 369,733 (93,224)
Net income (loss) 154,003 111,702 366,443 (90,538)
Common stock data:
Basic earnings per common share
Income from continuing operations 0.73 0.59 1.80 (0.44)
Net Income 0.77 0.56 1.78 (0.43)
Diluted earnings per common share
Income from continuing operations 0.73 0.58 1.79 (0.44)
Net Income 0.77 0.56 1.77 (0.42)
Dividends paid per common share 0.530 0.530 0.530 0.530
Market price per share - High 49.25 45.00 45.79 45.60
Low 38.78 40.36 39.25 40.50
o 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.
All amounts were restated for discontinued operations (See Note 3A).
o Second quarter of 2001 includes seven months of revenue related to Progress
Rail Services due to reversal of net assets held for sale accounting
treatment.
o Fourth quarter 2001 includes impairment and other charges related to
Strategic Resource Solutions Corp. and Interpath Communications, Inc. of
$209.0 million ($152.8 million after tax) (See Note 7).
o Third quarter 2002 includes impairment and other charges related to Progress
Telecom, Caronet and Interpath Communications, Inc. of $355.4 million
($224.8 million after tax) (See Note 7).
o Fourth quarter 2002 includes estimated impairment on assets held for sale of
Railcar Ltd. of $58.8 million ($40.1 million after tax) (See Note 3B).
See Notes to Consolidated Financial Statements.
6
PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Progress Energy, Inc. (Progress Energy or the Company) is a registered
holding company under the Public Utility Holding Company Act of 1935
(PUHCA), as amended. The Company and its subsidiaries are subject to the
regulatory provisions of PUHCA. The Company was formed as a result of the
reorganization of Carolina Power & Light Company (CP&L) into a holding
company structure (CP&L Energy, Inc.) on June 19, 2000. All shares of common
stock of CP&L were exchanged for an equal number of shares of CP&L Energy,
Inc. 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 and Florida Power Corporation
(Florida Power), the Company is primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina, South Carolina and Florida. Through the Progress Ventures business
unit, the Company is involved in nonregulated generation operations; natural
gas fuel exploration and production; coal fuel extraction, manufacturing and
delivery; and energy marketing and trading activities. Through the Rail
Services business unit, the Company is involved in nonregulated railcar
repair, rail parts reconditioning and sales, railcar leasing and sales, and
scrap metal recycling. Through its other business units, the Company engages
in other nonregulated business areas, including telecommunications and
holding company operations. Progress Energy's legal structure is not
currently aligned with the functional management and financial reporting of
the Progress Ventures business segment. Whether, and when, the legal and
functional structures will converge depends upon legislative and regulatory
action, which cannot currently be anticipated. Effective January 1, 2003,
CP&L, Florida Power and Progress Ventures, Inc. (PVI) began doing business
under the assumed names Progress Energy Carolinas, Inc., Progress Energy
Florida, Inc., and Progress Energy Ventures, Inc., respectively. The legal
names of these entities have not changed, and there is no restructuring of
any kind related to the name change. The current corporate and business unit
structure remains unchanged.
The Company's results of operations include the results of Florida Progress
Corporation (FPC) for the periods subsequent to November 30, 2000;
therefore, periods presented may not be comparable (See Note 2C).
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) 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. See Note 1K for a discussion of SFAS No. 71.
The accounting records of CP&L, Florida Power and North Carolina Natural Gas
Corporation (NCNG) 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).
Unconsolidated investments in companies over which the Company does not have
control, but has 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 equity and cost investments, which total approximately $108.9
million and $147.4 million at December 31, 2002 and 2001, respectively, are
included as miscellaneous other property and investments in the Consolidated
Balance Sheets. The primary component of this balance is the Company's
investments in affordable housing of $72.3 million and $82.4 million at
December 31, 2002 and 2001, respectively. Included in the December 31, 2001
investment balance is the Company's investment in Interpath Communications,
Inc. of $27.0 million.
7
Results of operations of Progress Rail Services Corporation and certain
other diversified operations are recognized one month in arrears.
Certain amounts for 2001 and 2000 have been reclassified to conform to the
2002 presentation.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and amounts
of revenues and expenses reflected during the reporting period. Actual
results could differ from those estimates.
D. Cash
The Company considers cash and cash equivalents to include unrestricted cash
on hand, cash in banks and temporary investments with a maturity of three
months or less.
E. Inventory
The Company accounts for inventory using the average-cost method. As of
December 31, inventory was comprised of (in thousands):
2002 2001
---------- ----------
Fuel $ 313,003 $ 296,772
Rail equipment and parts 155,206 200,697
Materials and supplies 362,708 349,127
Other 44,568 25,047
---------- ----------
Total inventory $ 875,485 $ 871,643
========== ==========
F. Utility Plant
Utility plant in service is stated at historical cost less accumulated
depreciation. The Company capitalizes all construction-related direct labor
and material costs of units of property as well as indirect construction
costs. The cost of renewals and betterments is also capitalized. Maintenance
and repairs of property, and replacements and renewals of items determined
to be less than units of property, are charged to maintenance expense as
incurred. 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 acquisition of FPC, the utility plants of
FPC continue to be presented on a gross basis to reflect the treatment of
such plant in cost-based regulation.
The balances of electric utility plant in service at December 31 are listed
below (in thousands), with a range of depreciable lives for each:
2002 2001
------------- -------------
Production plant (7-33 years) $ 11,062,405 $ 10,670,717
Transmission plant (30-75 years) 2,104,520 2,013,243
Distribution plant (12-50 years) 6,072,901 5,767,788
General plant and other (8-75 years) 912,961 724,273
------------- -------------
Utility plant in service $ 20,152,787 $ 19,176,021
============= =============
Generally, electric utility plant other than nuclear fuel is pledged as
collateral for the first mortgage bonds of CP&L and Florida Power (See Note
8).
8
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. 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 total
equity funds portion of AFUDC was $8.7 million, $8.8 million and $13.6
million in 2002, 2001 and 2000, respectively. The composite AFUDC rate for
CP&L's electric utility plant was 6.2% in both 2002 and 2001 and 8.2% in
2000. The composite AFUDC rate for Florida Power's electric utility plant
was 7.8% in 2002, 2001 and 2000.
G. Depreciation and Amortization - Utility Plant
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 1H) and excluding accelerated cost recovery of nuclear
generating assets, as a percent of average depreciable property other than
nuclear fuel, were approximately 3.6%, 4.0% and 4.1% in 2002, 2001 and 2000,
respectively. Total depreciation provisions were $730.3 million, $804.1
million and $707.5 million in 2002, 2001 and 2000, respectively.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost
recovery of its nuclear generating assets beginning January 1, 2000.
Cumulative accelerated depreciation ranging from $530 million to $750
million will be recorded by December 31, 2009. The accelerated cost recovery
of these assets resulted in additional depreciation expense of approximately
$53 million, $75 million and $275 million in 2002, 2001 and 2000,
respectively. Total accelerated depreciation recorded through December 31,
2002 was $326 million for the North Carolina jurisdiction and $77 million
for the South Carolina jurisdiction (See Note 15C).
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 units-of-production
method and charged to fuel used in electric generation in the accompanying
Consolidated Statements of Income. The total of these costs for the years
ended December 31, 2002, 2001 and 2000 were $141.1 million, $130.1 million
and $114.6 million, respectively.
Effective January 1, 2002 the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets," and no longer amortizes goodwill (See Note 6).
Prior to the adoption of SFAS No. 142, the Company amortized goodwill on a
straight-line basis over a period not exceeding 40 years. Intangible assets
are being amortized on a straight-line basis over their respective lives.
H. 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 $30.9 million, $38.5 million and $32.5
million in 2002, 2001 and 2000, respectively. The Florida Power rate case
settlement required Florida Power to suspend accruals on its reserves for
nuclear decommissioning and fossil dismantlement through December 31, 2005
(See Note 15B).
Accumulated decommissioning costs, which are included in accumulated
depreciation, were approximately $1.0 billion at December 31, 2002 and 2001.
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 unrealized gains and losses related
to changes in the fair value of trust assets.
9
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 years 2010 for Robinson Unit No. 2, 2016 for Brunswick
Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant. An
application to extend the Robinson license 20 years was submitted in 2002,
and a similar application will be made for the Brunswick units in 2004. An
extension will also be sought for the Harris Plant, tentatively scheduled
for 2009.
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, is
$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. An application to extend the plant license for 20 years is anticipated
to be submitted in 2007.
Management believes that decommissioning costs that have been and will be
recovered through rates by CP&L and Florida Power will be sufficient to
provide for the costs of decommissioning.
Florida Power maintains a reserve for fossil plant dismantlement. At
December 31, 2002 and 2001, this reserve was approximately $141.6 million
and $140.5 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
2001 annual provision, approved by the FPSC, was $8.8 million. The accrual
for fossil dismantlement reserves was suspended again in 2002 by the Florida
rate case settlement (See Note 15B).
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations," that will change the
accounting for the decommissioning and dismantlement provisions beginning in
2003 (See Note 1U).
I. Diversified Business Property
Diversified business property is stated at cost less accumulated
depreciation. If an impairment is recognized on an asset, the fair value
becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis using the
estimated useful lives indicated in the table below. Depletion of mineral
rights is provided on the units-of-production method based upon the
estimates of recoverable amounts of clean mineral.
The Company uses the full cost method to account for its natural gas and oil
properties. Under the full cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition, exploration
and development of natural gas and oil reserves are capitalized. These
capitalized costs include the costs of all unproved properties, internal
costs directly related to acquisition and exploration activities. These
costs are amortized using the units-of-production method over the life of
the Company's proved reserves. Total capitalized costs are limited to a
ceiling based on the present value of discounted (at 10%) future net
revenues using current prices, plus the lower of cost or fair market value
of unproved properties. If the ceiling (discounted revenues) is not equal to
or greater than total capitalized costs, the Company is required to
write-down capitalized costs to this level. The Company performs this
ceiling test calculation every quarter. No write-downs were required in
2002, 2001 or 2000.
The Company's nonregulated businesses capitalize interest costs under SFAS
No. 34, "Capitalizing Interest Costs." During the year ended December 31,
2002, the Company capitalized $38.2 million of its interest expense of
$679.8 million related to the expansion of its nonregulated generation
portfolio at PVI. Capitalized interest is included in diversified business
property, net on the Consolidated Balance Sheets.
10
Diversified business depreciation expense was $86.2 million, $72.3 million
and $18.5 million at December 31, 2002, 2001 and 2000, respectively.
The following is a summary of diversified business property (in thousands)
as of December 31, with ranges of depreciable lives:
2002 2001
------------ ------------
Equipment (3 - 25 years) $ 298,747 $ 228,673
Nonregulated generation plant and equipment (3 - 40 years) 549,115 108,512
Land and mineral rights 89,506 76,598
Buildings and plants (5 - 40 years) 153,186 125,032
Oil and gas properties (units-of-production) 264,767 41,413
Telecommunications equipment (5 - 20 years) 42,514 266,603
Rail equipment (3 - 20 years) 48,279 54,105
Marine equipment (3 - 35 years) 80,501 78,868
Computers, office equipment and software (3 - 10 years) 33,575 42,855
Construction work in progress 643,742 342,179
Accumulated depreciation (319,661) (292,715)
------------ ------------
Diversified business property, net $ 1,884,271 $ 1,072,123
============ ============
During 2002, the Company recorded asset impairments related to assets held
by the Company's telecommunications operations (See Note 7).
J. Impairment of Long-Lived Assets and Investments
The Company reviews the recoverability of long-lived and intangible assets
whenever indicators exist. Examples of these indicators include current
period losses, combined with a history of losses or a projection of
continuing losses, or a significant decrease in the market price of a
long-lived asset group. If an indicator exists for assets to be held and
used, then the asset group is tested for recoverability by comparing the
carrying value to the sum of undiscounted expected future cash flows
directly attributable to the asset group. If the asset group is not
recoverable through undiscounted cash flows or the asset group is to be
disposed of, then an impairment loss is recognized for the difference
between the carrying value and the fair value of the asset group. The
accounting for impairment of assets is based on SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," which was adopted by
the Company effective January 1, 2002. Prior to the adoption of this
standard, impairments were accounted for under SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," which was superceded by SFAS No. 144. See Note 7 for a discussion of
impairment evaluations performed and charges taken.
K. Cost-Based Regulation
The Company's regulated operations are subject to SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation." SFAS No. 71 allows a
regulated company to record costs that have been or are expected to be
allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by a nonregulated enterprise.
Accordingly, the Company records assets and liabilities that result from the
regulated ratemaking process that would not be recorded under GAAP for
nonregulated entities. These regulatory assets and liabilities represent
expenses deferred for future recovery from customers or obligations to be
refunded to customers and are primarily classified in the accompanying
Consolidated Balance Sheets as regulatory assets and regulatory liabilities
(See Note 15A).
L. Income Taxes
The Company and its affiliates file a consolidated federal income tax
return. Deferred income taxes have been provided for temporary differences.
These occur when there are differences between the book and tax carrying
amounts of assets and liabilities. Investment tax credits related to
regulated operations have been deferred and are being amortized over the
estimated service life of the related properties. Credits for the production
and sale of synthetic fuel are deferred to the extent they cannot be or have
not been utilized in the annual consolidated federal income tax returns (See
Note 20).
11
M. Excise Taxes
CP&L and Florida Power collect from customers certain excise taxes levied by
the state or local government upon the customers. CP&L and Florida Power
account for excise taxes on a gross basis. For the years ended December 31,
2002, 2001 and 2000, gross receipts tax, franchise taxes and other excise
taxes of approximately $211.0 million, $209.8 million and $84.0 million,
respectively, are included in taxes other than on income in the accompanying
Consolidated Statements of Income. These approximate amounts are also
included in utility revenues.
N. Derivatives
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 balance
sheet and measure those instruments at fair value. See Note 16 for
information regarding risk management activities and derivative
transactions.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivatives
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices. In particular, that guidance discusses
whether the pricing in a contract that contains broad market indices (e.g.,
CPI) could qualify as a normal purchase or sale (the normal purchase or sale
term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
The Company is currently reevaluating which contracts, if any, that have
previously been designated as normal purchases or sales would now not
qualify for this exception. The Company is currently evaluating the effects
that this guidance will have on its results of operations and financial
position.
O. Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts receivable, which
totaled approximately $39.6 million and $38.7 million at December 31, 2002
and 2001, respectively.
P. Unamortized Debt Premiums, Discounts and Expenses
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 applicable life
using the straight-line method consistent with ratemaking treatment.
Q. Revenue Recognition
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." Gains and losses from energy trading activities are reported on a
net basis. Revenues related to design and construction of wireless
infrastructure are recognized upon completion of services for each completed
phase of design and construction.
R. Fuel Cost Deferrals
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.
12
S. Environmental
The Company accrues environmental remediation liabilities when the criteria
for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental
expenditures are expensed as incurred or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Accruals for estimated losses from environmental remediation
obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as additional
information develops or circumstances change. Costs of future expenditures
for environmental remediation obligations are not discounted to their
present value. Recoveries of environmental remediation costs from other
parties are recognized when their receipt is deemed probable (See Note 24E).
T. Benefit Plans
The Company follows the guidance in SFAS No. 87, "Employers' Accounting for
Pensions," to account for its defined benefit retirement plans. In addition
to pension benefits, the Company provides other postretirement benefits
which are accounted for under SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." See Note 18 for related
disclosures for these plans.
U. New Accounting Standards
SFAS No. 143, "Accounting for Asset Retirement Obligations"
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
in July 2001. This statement provides accounting and disclosure requirements
for retirement obligations associated with 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 liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation will be recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of this
statement. The cumulative effect of initially applying this statement is
recognized as a change in accounting principle. The adoption of this
statement will have no impact on the income of regulated entities, as the
effects are expected to be offset by the establishment of regulatory assets
or liabilities pursuant to SFAS No. 71.
The Company's review identified legal retirement obligations for nuclear
decommissioning of radiated plant, coal mine operations, synthetic fuel
operations and gas production. The Company will record liabilities pursuant
to SFAS No. 143 beginning in 2003. The Company used an expected cash flow
approach to measure the obligations. The following proforma liabilities
reflect amounts as if this statement had been applied during all periods (in
millions):
Liability as of December 31, 2002 2001
---------- -----------
Regulated:
Nuclear decommissioning $ 1,182.5 $ 1,117.7
Nonregulated:
Coal mine operations $ 6.1 $ 5.6
Synfuel operations 2.0 1.7
Gas production 2.2 2.0
Nuclear decommissioning and coal mine operations have previously-recorded
liabilities. Amounts recorded for nuclear decommissioning of radiated plant
were $775.1 million and $737.1 million at December 31, 2002 and 2001,
respectively. Amounts recorded for coal mine reclamation were $4.7 million
and $4.8 million at December 31, 2002 and 2001, respectively. Synthetic fuel
operations and gas production have no previously-recorded liabilities.
Proforma net income and earnings per share have not been presented for the
years ended December 31, 2002, 2001 and 2000 because the proforma
application of SFAS No. 143 to prior periods would result in proforma net
income and earnings per share not materially different from the actual
amounts reported for those periods in the accompanying Consolidated
Statements of Income.
13
The Company has identified but not recognized asset retirement obligation
(ARO) liabilities related to electric transmission and distribution, gas
distribution and telecommunications assets as the result of easements over
property not owned by the Company. These easements are generally perpetual
and only require retirement action upon abandonment or cessation of use of
the property for the specified purpose. The ARO liability is not estimable
for such easements as the Company intends to utilize these properties
indefinitely. In the event the Company decides to abandon or cease the use
of a particular easement, an ARO liability would be recorded at that time.
The utilities have previously recognized removal costs as a component of
depreciation in accordance with regulatory treatment. To the extent these
amounts do not represent SFAS No. 143 legal retirement obligations, they
will be disclosed as regulatory liabilities upon adoption of the standard.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" In April 2002, the FASB
issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections." This newly
issued statement rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt (an amendment of APB Opinion No. 30)," which required
all gains and losses from the extinguishment of debt to be aggregated and,
if material, classified as an extraordinary item, net of related income tax
effect. As a result, the criteria set forth by APB Opinion 30 will now be
used to classify those gains and losses. Any gain or loss on extinguishment
will be recorded in the most appropriate line item to which it relates
within net income before extraordinary items. For regulated companies, any
expenses or call premiums associated with the reacquisition of debt
obligations are amortized over the applicable life using the straight-line
method consistent with ratemaking treatment (See Note 1P). SFAS No. 145 also
amends SFAS No. 13 to require that certain lease modifications that have
economic effects similar to sale-leaseback transactions be accounted for in
the same manner as sale-leaseback transactions. In addition, SFAS No. 145
amends other existing authoritative pronouncements to make various technical
corrections, clarify meanings or describe their applicability under changed
conditions. For the provisions related to the rescission of SFAS No. 4, SFAS
No. 145 is effective for the Company beginning in fiscal year 2004. The
remaining provisions of SFAS No. 145 are effective for the Company in fiscal
year 2003. The Company is currently evaluating the effects, if any, that
this statement will have on its results of operations and financial
position.
SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure"
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure -- an Amendment of FASB Statement
No. 123," and provided alternative methods of transition for a voluntary
change to the fair value-based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements
of SFAS No. 123, "Accounting for Stock-Based Compensation," to require
prominent disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. This statement requires that
companies follow the prescribed format and provide the additional
disclosures in their annual reports for years ending after December 15,
2002. The Company applies the recognition and measurement principles of APB
Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by
SFAS Nos. 123 and 148, and related interpretations in accounting for its
stock-based compensation plans, as described in Note 17.
14
For purposes of the proforma disclosures required by SFAS No. 148, the
estimated fair value of the options is amortized to expense over the
options' vesting period. Under SFAS No. 123, compensation expense would have
been $13.5 million and $2.9 million in 2002 and 2001, respectively. The
stock option plan was not in effect in 2000. The Company's information
related to the proforma impact on earnings and earnings per share follows.
(in thousands except per share data) 2002 2001 2000
---------- ---------- ----------
Net income, as reported $ 528,386 $ 541,610 $ 478,361
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 8,036 1,765 -
---------- ---------- ----------
Proforma net income $ 520,350 $ 539,845 $ 478,361
========== ========== ==========
Earnings per share:
Basic - as reported $2.43 $2.65 $3.04
Basic - proforma $2.40 $2.64 $3.04
Diluted - as reported $2.42 $2.64 $3.03
Diluted - proforma $2.39 $2.63 $3.03
FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an Interpretation of FASB Statements
No. 5, 57 and 107 and Rescission of FASB Interpretation No. 34" (FIN No.
45). This interpretation clarifies the disclosures to be made by a guarantor
in its interim and annual financial statements about obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of certain guarantees, a liability
for the fair value of the obligation undertaken in issuing the guarantee.
The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements are effective
for financial statements of interim or annual periods ending after December
15, 2002. The applicable disclosures required by FIN No. 45 have been made
in Notes 9 and 24C. The Company is currently evaluating the effects, if any,
that this interpretation will have on its results of operations and
financial position.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities (previously known generally as special purpose entities or
SPEs) and determining whether such entities should be consolidated. Certain
disclosures are required when FIN No. 46 becomes effective if it is
reasonably possible that a company will consolidate or disclose information
about a variable interest entity when it initially applies FIN No. 46. This
interpretation must be applied immediately to variable interest entities
created or obtained after January 31, 2003. For those variable interest
entities created or obtained on or before January 31, 2003, the Company must
apply the provisions of FIN No. 46 in the third quarter of 2003.
The Company has an arrangement with Railcar Asset Financing Trust (RAFT),
through its Railcar Ltd. subsidiary, to which this interpretation may apply.
Because the Company expects to sell Railcar Ltd. during 2003 (See Note 3B),
the application of FIN No. 46 is not expected to have a material impact with
respect to this arrangement. The Company is currently evaluating what
effects, if any, this interpretation will have on its results of operations
and financial position.
EITF Issue 02-03, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities."
In June 2002, the EITF reached a consensus on a portion of Issue 02-03,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF Issue 02-03 requires all gains and losses (realized or
unrealized) on energy trading contracts to be shown net in the income
statement. The Company's policy already required the gains and losses to be
recorded on a net basis. The net of the gains and losses are recorded in
diversified business revenue and other, net on the Consolidated Statements
of Income. The Company does not recognize a dealer profit or unrealized gain
or loss at the inception of a derivative unless the fair value of that
instrument, in its entirety, is evidenced by quoted market prices or current
market transactions.
15
2. Acquisitions
A. Generation Acquisition
On February 15, 2002, PVI acquired 100% of two electric generating projects
located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. The
two projects consist of 1) Walton County Power, LLC in Monroe, Georgia, a
460 megawatt natural gas-fired plant placed in service in June 2001 and 2)
Washington County Power, LLC in Washington County, Georgia, a planned 600
megawatt natural gas-fired plant expected to be operational by June 2003.
The Walton and Washington projects have been accounted for using the
purchase method of accounting and accordingly have been included in the
consolidated financial statements since the acquisition date.
In the final allocation, the aggregate cash purchase price of approximately
$347.9 million was allocated to diversified business property, intangibles
and goodwill for $250.4 million, $33.4 million and $64.1 million,
respectively. Of the acquired intangible assets, $33.0 million was assigned
to tolling and power sale agreements with LG&E Energy Marketing, Inc. for
each project and is being amortized through December 31, 2004. Goodwill was
assigned to the Progress Ventures segment and will be deductible for tax
purposes (See Note 6).
In addition, PVI entered into a project management and completion agreement
whereby LG&E Energy Corp. agreed to manage the completion of the Washington
site construction for PVI. As of December 31, 2002, the remaining payments
related to the agreement are estimated to be $57.8 million. The Company has
guaranteed certain payments on behalf of PVI related to the construction of
the facility (See Note 24C).
The proforma results of operations reflecting the acquisition would not be
materially different than the reported results of operations for the years
ended December 31, 2002 or 2001.
B. Westchester Acquisition
On April 26, 2002, Progress Fuels Corporation (Progress Fuels), a subsidiary
of Progress Energy, acquired 100% of Westchester Gas Company (Westchester).
The acquisition included approximately 215 natural gas-producing wells, 52
miles of intrastate gas pipeline and 170 miles of gas-gathering systems
located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border.
The aggregate purchase price of approximately $153 million consisted of cash
consideration of approximately $22 million and the issuance of 2.5 million
shares of Progress Energy common stock valued at approximately $129 million.
The purchase price included approximately $2 million of direct transaction
costs. The purchase price has been preliminarily allocated to fixed assets
including oil and gas properties, based on the preliminary fair values of
the assets acquired. The preliminary purchase price allocation is subject to
adjustment for changes in the preliminary assumptions pending additional
information, including final asset valuations.
The acquisition has been accounted for using the purchase method of
accounting and, accordingly, the results of operations for Westchester have
been included in Progress Energy's consolidated financial statements since
the date of acquisition. The proforma results of operations reflecting the
acquisition would not be materially different than the reported results of
operations for the years ended December 31, 2002 or 2001.
C. Florida Progress Corporation Acquisition
On November 30, 2000, the Company completed its acquisition of FPC, a
diversified, exempt electric utility holding company, 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 (CVOs) valued at approximately
$49.3 million (See Note 10). The purchase price included $20.1 million in
direct transaction costs.
16
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. The excess of the purchase price over the fair value of the net
identifiable assets and liabilities acquired was 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 6).
The U.S. Securities and Exchange Commission (SEC) order approving the merger
requires the Company to divest of Rail Services and certain immaterial,
nonregulated investments of FPC by November 30, 2003. The Company is
evaluating opportunities and actively marketing these investments but may
not find the right divestiture opportunity by that date. Therefore, the
Company plans to seek an extension from the SEC.
3. Divestitures
A. NCNG Divestiture
On October 16, 2002, the Company announced the Board of Directors' approval
to sell NCNG and the Company's equity investment in Eastern North Carolina
Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc., for
approximately $400 million in net proceeds. The sale is expected to close by
summer of 2003 and must be approved by the NCUC and federal regulatory
agencies.
The accompanying consolidated financial statements have been restated for
all periods presented for the discontinued operations of NCNG. The net
income of these operations is reported as discontinued operations in the
Consolidated Statements of Income. Interest expense of $15.6 million, $14.5
million and $13.6 million for the years ended December 31, 2002, 2001 and
2000, respectively, has been allocated to discontinued operations based on
the net assets of NCNG, assuming a uniform debt-to-equity ratio across the
Company's operations. The Company ceased recording depreciation effective
October 1, 2002, upon classification of the assets as discontinued
operations. The asset group, including goodwill, has been recorded at fair
value less cost to sell, resulting in an estimated loss on disposal of
approximately $29.4 million, which has been recorded until the disposition
is complete and the actual loss can be determined. Results of discontinued
operations for years ended December 31, were as follows:
(in thousands) 2002 2001 2000
---------- ---------- -----------
Revenues $ 299,820 $ 321,422 $ 330,365
========== ========== ===========
Earnings before income taxes $ 8,944 $ 3,909 $ 6,711
Income tax expense 3,350 2,695 6,272
---------- ---------- -----------
Net earnings from discontinued operations 5,594 1,214 439
---------- ---------- -----------
Estimated loss on disposal of discontinued operations,
including applicable income tax expense of $3,214 (29,377) - -
---------- ----------- -----------
Earnings (loss) from discontinued operations $ (23,783) $ 1,214 $ 439
========== =========== ===========
The major balance sheet classes included in assets and liabilities of
discontinued operations in the Consolidated Balance Sheets, as of December
31, are as follows:
(in thousands) 2002 2001
---------- ----------
Utility plant, net $ 398,931 $ 393,149
Current assets 72,821 116,969
Deferred debits and other assets 18,677 42,340
---------- ----------
Assets of discontinued operations $ 490,429 $ 552,458
========== ==========
Current liabilities $ 76,372 $ 126,208
Deferred credits and other liabilities 48,395 36,709
---------- ----------
Liabilities of discontinued operations $ 124,767 $ 162,917
========== ==========
17
The Company's equity investment in ENCNG of $7.7 million as of December 31,
2002 is included in miscellaneous other property and investments in the
Consolidated Balance Sheets.
B. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution approving the sale of Railcar Ltd., a subsidiary included in the
Rail Services segment. A series of sales transactions is expected to take
place throughout 2003. In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," an estimated impairment on
assets held for sale of $58.8 million has been recognized for the write-down
of the assets to be sold to fair value less the costs to sell. This
impairment has been included in impairment of long-lived assets in the
Consolidated Statements of Income (See Note 7).
The assets of Railcar Ltd. have been grouped as assets held for sale and are
included in other current assets on the Consolidated Balance Sheets as of
December 31, 2002. The assets are recorded at $23.6 million, which reflects
the Company's initial estimate of the fair value expected to be realized
from the sale of these assets. The primary component of assets held for sale
is current assets of $21.6 million. These assets are subject to certain
commitments under operating leases (See Note 12). The Company expects to be
relieved of the majority of these commitments as a result of the sale.
C. Inland Marine Transportation Divestiture
During 2001, the Company completed the sale of its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc., 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. In
connection with the sale, the Company entered into environmental
indemnification provisions covering both known and unknown sites (See Note
24E).
The Company adjusted the FPC purchase price allocation to reflect a $15.0
million negative net realizable value of the Inland Marine business. The
Company's results of operations exclude Inland Marine Transportation 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 the purchase price allocation.
D. BellSouth Carolinas PCS Partnership Interest Divestiture
In September 2000, Caronet, Inc. (Caronet), 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.
4. 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.
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. These electric
operations are subject to the rules and regulations of FERC, the NCUC, the
SCPSC and the FPSC.
The Progress Ventures segment operations include nonregulated generation
operations; natural gas exploration and production; coal fuel extraction,
manufacturing and delivery; and energy marketing and limited trading
activities on behalf of the utility operating companies as well as for its
nonregulated plants. Management reviews the operations of the segment after
the allocation of energy marketing and trading activities, which Progress
Ventures performs on behalf of the regulated utilities, CP&L and Florida
Power.
The Rail Services segment operations include railcar repair, rail parts
reconditioning and sales, railcar leasing and sales, and scrap metal
recycling. These activities include maintenance and reconditioning of
salvageable scrap components of railcars, locomotive repair and right-of-way
maintenance. Included in this segment is an estimated impairment on assets
held for sale (See Note 3B).
18
The Other segment is made up of other nonregulated business areas including
telecommunications and holding company operations. The discontinued
operations related to the sale of NCNG are not included in the operating
segments below (See Note 3A).
(In thousands) Florida
Power Progress Rail
CP&L Electric Ventures Services Consolidated
Electric (c) (c) (b) Other Totals
FOR THE YEAR ENDED DECEMBER 31, 2002
Revenues
Unaffiliated $3,538,957 $3,061,732 $748,317 $714,499 ($118,385) $7,945,120
Intersegment - - 326,639 4,623 (331,262) -
----------------------------------------------------------------------------
Total revenues 3,538,957 3,061,732 1,074,956 719,122 (449,647) 7,945,120
Depreciation and amortization 523,846 294,856 67,295 20,436 33,495 939,928
Net interest charges 211,536 106,783 12,132 32,767 270,223 633,441
Impairments of long-lived assets and
investments
(Notes 3B and 7) - - - 58,836 329,997 388,833
Income taxes (benefit) (e) 237,362 163,273 (359,862) (15,370) (183,211) (157,808)
Income (loss) from continuing operations 513,115 322,594 198,088 (41,733) (439,895) 552,169
Segment income (loss) from continuing
operations after allocation (a) 453,115 309,594 271,088 (41,733) (439,895) 552,169
Total segment assets (d) 8,659,297 5,226,243 2,354,081 614,640 4,008,014 20,862,275
Capital and investment expenditures 624,202 550,019 805,609 8,332 120,968 2,109,130
=======================================================================================================================
FOR THE YEAR ENDED DECEMBER 31, 2001
Revenues
Unaffiliated $3,343,720 $3,212,841 $526,200 $890,328 $112,291 $8,085,380
Intersegment - - 398,228 1,174 (399,402) -
----------------------------------------------------------------------------
Total revenues 3,343,720 3,212,841 924,428 891,502 (287,111) 8,085,380
Depreciation and amortization 521,910 452,971 40,695 36,053 109,615 1,161,244
Net interest charges 241,427 113,707 24,085 40,589 253,085 672,893
Impairment of long-lived assets and
investments
(Note 7) - - - - 207,035 207,035
Income taxes (benefit) 264,078 182,590 (421,559) (6,416) (173,031) (154,338)
Income (loss) from continuing operations 468,328 309,576 201,990 (12,108) (427,390) 540,396
Segment income (loss) from continuing
operations after allocation (a) 405,661 285,566 288,667 (12,108) (427,390) 540,396
Total segment assets 8,884,385 5,009,640 1,018,875 602,597 4,822,746 20,338,243
Capital and investment expenditures 823,952 353,433 265,183 12,886 71,986 1,527,440
=======================================================================================================================
FOR THE YEAR ENDED DECEMBER 31, 2000
Revenues
Unaffiliated $3,308,215 $ 241,606 $108,739 $ - $110,362 $3,768,922
Intersegment - - 15,717 - (15,717) -
----------------------------------------------------------------------------
Total revenues 3,308,215 241,606 124,456 - 94,645 3,768,922
Depreciation and amortization 698,633 28,872 17,020 - 15,657 760,182
Net interest charges 221,856 9,777 5,714 - 5,231 242,578
Gain on sale of investment - - - - 200,000 200,000
Income taxes (benefit) 227,705 13,580 (109,057) - 64,274 196,502
Income (loss) from continuing operations 373,764 21,764 39,816 - 42,578 477,922
Segment income (loss) from continuing
operations after allocation (a) 289,724 20,057 125,563 - 42,578 477,922
Total segment assets 8,840,736 4,997,728 644,234 - 4,515,053 18,997,751
Capital and investment expenditures 821,991 49,805 38,981 - 100,317 1,011,094
=======================================================================================================================
(a) Includes allocation of energy marketing and trading 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. During 2001, the Company announced its intention to retain the
Rail Services segment and, therefore, these assets were reclassified to
operating assets.
(c) Amounts for the year ended December 31, 2000, reflect operating results of
Florida Power electric since the acquisition date of November 30, 2000 (See
Note 2C).
(d) In February 2002, CP&L transferred the Rowan Plant totaling approximately
$245 million to Progress Ventures.
(e) 2002 includes income tax benefit reallocation from holding company to
profitable subsidiaries according to an SEC order.
19
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.
5. Related Party Transactions
NCNG sells natural gas to CP&L, Florida Power and PVI. During the years
ended December 31, 2002, 2001 and 2000, sales of natural gas to CP&L,
Florida Power and PVI amounted to $19.5 million, $18.7 million and $5.9
million, respectively. These revenues are included in discontinued
operations on the Consolidated Statements of Income. Progress Fuels sells
coal to Florida Power. These intercompany revenues are eliminated in
consolidation; however, in accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulations," 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 ratemaking process is
probable.
The Company and its operating subsidiaries participate in a money pool
arrangement to better manage cash and working capital requirements. Under
this arrangement, subsidiaries with surplus short-term funds provide
short-term loans to participating affiliates.
The Company has announced plans to sell NCNG to Piedmont Natural Gas
Company, Inc. (See Note 3A). At December 31, 2002 and 2001, the Company and
its affiliates had amounts due from and payable to NCNG. Under the terms of
the sales agreement, these amounts will be settled at the time of the
transaction and therefore, the amounts are no longer being eliminated in
consolidation. The receivables due from and the payables due to the Company
are included in assets of discontinued operations and liabilities of
discontinued operations, respectively, on the Consolidated Balance Sheets.
At December 31, 2002 and 2001, NCNG had notes payable balances due to the
Company related to the money pool of $5.8 million and $51.7 million,
respectively. Interest payable balances as of December 31, 2002 and 2001 and
amounts recorded for interest income and interest expense related to the
money pool for 2002, 2001 and 2000 were not significant. The remaining
amounts of receivables and payables with the Company and its affiliates at
December 31, 2002 and 2001 represent amounts generated through NCNG's normal
course of operations. NCNG had payables to the Company of $5.0 million and
$31.9 million and receivables from the Company of $3.6 million and $51.9
million at December 31, 2002 and 2001, respectively.
In 2000, 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 (See Note 2C).
6. Goodwill and Other Intangible Assets
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets." This statement 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 two-step fair value-based test. This
assessment could result in periodic impairment charges.
The Company completed the first step of the initial transitional goodwill
impairment test, which indicated that the Company's goodwill was not
impaired as of January 1, 2002. In addition, the Company performed the
annual goodwill impairment tests for the CP&L Electric and Florida Power
Electric segments during the second quarter 2002, which indicated that the
Company's goodwill was not impaired. The annual test for Progress Ventures'
goodwill will be performed during 2003.
20
In connection with the pending sale of NCNG, goodwill attributable to these
operations has been reclassified to assets of discontinued operations. The
Company reviewed the carrying value of the NCNG disposal group in accordance
with SFAS No. 144 (See Note 3A).
The changes in the carrying amount of goodwill for the year ended December
31, 2002, by reportable segment, are as follows:
Florida Power Progress
(In thousands) CP&L Electric Electric Ventures Other Total
Balance as of January 1, 2002 $ 1,921,802 $ 1,733,448 $ - $ 34,960 $ 3,690,210
Acquisitions - - 64,077 - 64,077
Divestitures - - - (1,720) (1,720)
Discontinued operations - - - (33,240) (33,240)
------------------------------------------------------------------------------
Balance as of December 31, 2002 $ 1,921,802 $ 1,733,448 $ 64,077 $ - $ 3,719,327
==============================================================================
The acquired goodwill relates to the acquisition of generating assets from
LG&E Energy Corp. in February 2002 (See Note 2A).
As required by SFAS No. 142, the results for the prior year periods have not
been restated. A reconciliation of net income as if SFAS No. 142 had been
adopted is presented below for years ending December 31. The goodwill
amortization used in the reconciliation includes $5.9 million for both years
ending December 31, 2001 and 2000 for NCNG, which is included in
discontinued operations.
(In thousands, except per share data) 2001 2000
----------- ----------
Reported net income $ 541,610 $ 478,361
Goodwill amortization 96,828 14,100
----------- ----------
Adjusted net income $ 638,438 $ 492,461
=========== ==========
Basic earnings per common share:
Reported net income $ 2.65 $ 3.04
Adjusted net income $ 3.12 $ 3.13
Diluted earnings per common share:
Reported net income $ 2.64 $ 3.03
Adjusted net income $ 3.11 $ 3.12
The gross carrying amount and accumulated amortization of the Company's
intangible assets as of December 31, 2002 and 2001 are as follows:
2002 2001
------------------------------------- ---------------------------------
(In thousands) Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
----------------------------------- ---------------------------------
Synthetic fuel intangibles $ 140,469 $ (45,189) $ 140,469 $ (22,237)
Power sale agreements 33,000 (5,593) - -
Other 40,968 (7,792) 36,071 (5,938)
----------------------------------- ---------------------------------
Total $ 214,437 $ (58,574) $ 176,540 $ (28,175)
=================================== =================================
All of the Company's intangibles are subject to amortization. Synthetic fuel
intangibles represent intangibles for synthetic fuel technology. These
intangibles are being amortized on a straight-line basis until the
expiration of tax credits under Section 29 of the Internal Revenue Code in
December 2007 (See Note 20). The power sale agreement intangibles were
recorded as part of the acquisition of generating assets from LG&E Energy
Corp. and are amortized on a straight-line basis beginning with the
in-service date of these plants through December 31, 2004 (See Note 2A).
Other intangibles are primarily customer contracts and permits that are
amortized over their respective lives.
Net intangible assets are included in other assets and deferred debits in
the accompanying Consolidated Balance Sheets. Amortization expense recorded
on intangible assets for the years ended December 31, 2002, 2001 and 2000
were $32.8 million, $21.6 million and $6.3 million, respectively. The
estimated amortization expense for intangible assets for 2003 through 2007,
in millions, is approximately $33.5, $36.5, $20.3, $19.8 and $19.8,
respectively.
21
7. Impairments of Long-Lived Assets and Investments
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." In 2002 and 2001, the Company recorded pre-tax long-lived asset and
investment impairments of approximately $388.8 million and $209.0 million,
respectively. There were no impairments recorded in 2000. Estimated
impairments of assets held for sale of $58.8 million is included in the 2002
amount, which relates to Railcar Ltd. (See Note 3B).
A. Long-Lived Assets
Due to the decline of the telecommunications industry and continued
operating losses, the Company initiated an independent valuation study
during 2002 to assess the recoverability of the long-lived assets of
Progress Telecommunications Corporation (Progress Telecom) and Caronet.
Based on this assessment, the Company recorded asset impairments of $305.0
million on a pre-tax basis and other charges of $25.4 million on a pre-tax
basis primarily related to inventory adjustments in the third quarter of
2002. This write-down constitutes a significant reduction in the book value
of these long-lived assets.
The long-lived asset impairments include an impairment of property, plant
and equipment, construction work in process and intangible assets. The
impairment charge represents the difference between the fair value and
carrying amount of these long-lived assets. The fair value of these assets
was determined using a valuation study heavily weighted on the discounted
cash flow methodology, using market approaches as supporting information.
Due to historical losses at Strategic Resource Solutions Corp. (SRS) and the
decline in the market value for technology companies, the Company evaluated
the long-lived assets of SRS in 2001. Fair value was determined based on
discounted cash flows. As a result of this review, the Company recorded
asset impairments of $42.9 million and other charges of $1.9 million on a
pre-tax basis during the fourth quarter of 2001.
B. Investments
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, Caronet entered into an agreement with Bain Capital
whereby it contributed the net assets used in its application service
provider business to a newly formed company, named Interpath Communications,
Inc. (Interpath), for a 35% ownership interest (15% voting interest) in
Interpath. In 2001, 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 recorded an impairment 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. In May 2002, Interpath
merged with a third party. Pursuant to the terms of the merger agreement and
due to additional funds being contributed by Bain Capital, the Company's
ownership was diluted to 19% (7% voting interest). As a result, the Company
reviewed the Interpath investment for impairment and wrote off the remaining
amount of its cost-basis investment in Interpath, recording a pre-tax
impairment of $25.0 million in the third quarter of 2002. In the fourth
quarter of 2002, the Company sold its remaining interest in Interpath for a
nominal amount.
22
8. Debt and Credit Facilities
A. Debt and Credit
At December 31, 2002 and 2001 the Company's long-term debt consisted of the
following (maturities and weighted-average interest rates as of December 31,
2002):
(in thousands) 2002 2001
--------------- ----------------
Progress Energy, Inc.:
Senior unsecured notes, maturing 2004-2031 6.93% $ 4,800,000 $4,000,000
Unamortized fair value hedge gain 33,676 -
Unamortized premium and discount, net (31,256) (29,708)
--------------- ----------------
4,802,420 3,970,292
--------------- ----------------
Carolina Power & Light Company:
First mortgage bonds, maturing 2004-2023 6.92% 1,550,000 1,800,000
Pollution control obligations, maturing 2010-2024 1.86% 707,800 707,800
Unsecured notes, maturing 2012 6.50% 500,000 -
Extendible notes, maturing 2002 - - 500,000
Medium-term notes, maturing 2008 6.65% 300,000 300,000
Miscellaneous notes 6.44% 6,910 7,234
Unamortized premium and discount, net (16,244) (16,716)
--------------- ----------------
3,048,466 3,298,318
--------------- ----------------
Florida Power Corporation:
First mortgage bonds, maturing 2003-2023 6.83% 810,000 810,000
Pollution control obligations, maturing 2018-2027 1.11% 240,865 240,865
Medium-term notes, maturing 2003-2028 6.74% 416,900 449,100
Unamortized premium and discount, net (6,433) (2,935)
--------------- ----------------
1,461,332 1,497,030
--------------- ----------------
Progress Ventures Holdings, Inc.:
Variable rate project financing, maturing 2007 3.02% 225,000 -
Florida Progress Funding Corporation (Note 9):
Mandatorily redeemable preferred securities, maturing 2039 7.10% 300,000 300,000
Purchase accounting fair value adjustment (30,276) (30,413)
Unamortized premium and discount, net (8,680) (8,922)
--------------- ----------------
261,044 260,665
--------------- ----------------
Progress Capital Holdings, Inc.:
Medium-term notes, maturing 2003-2008 6.96% 223,000 273,000
Miscellaneous notes 1.53% 1,428 7,707
--------------- ----------------
224,428 280,707
--------------- ----------------
Current portion of long-term debt (275,397) (688,052)
--------------- ----------------
Total Long-Term Debt, Net $ 9,747,293 $ 8,618,960
=============== ================
As of December 31, 2002 and 2001, the Company had $694.9 million and $942.3
million, 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, 2002 and 2001 were
1.67% and 2.95%, respectively. The Company no longer reclassifies commercial
paper to long-term debt. Certain amounts for 2001 have been reclassified to
conform to 2002 presentation, with no effect on previously reported net
income or common stock equity.
At December 31, 2002, the Company had committed lines of credit totaling
$1.74 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 (in millions):
23
Company Description Total
----------------------------------------------------------------
Progress Energy 364-Day (expiring 11/11/03) $ 430.2
Progress Energy 3-Year (expiring 11/13/04) 450.0
CP&L 364-Day (expiring 7/30/03) 285.0
CP&L 3-Year (expiring 7/31/05) 285.0
Florida Power 364-Day (expiring 4/1/03) 90.5
Florida Power 5-Year (expiring 11/30/03) 200.0
----------
$ 1,740.7
==========
As of December 31, 2002, there were no loans outstanding under these
facilities.
Progress Energy and Florida Power each have an uncommitted bank bid facility
authorizing them to borrow and re-borrow, and have loans outstanding at any
time, up to $300 million and $100 million, respectively. These bank bid
facilities were not drawn as of December 31, 2002.
The combined aggregate maturities of long-term debt for 2003 through 2007
are approximately $275 million, $869 million, $355 million, $909 million,
and $899 million, respectively.
B. Covenants and Default Provisions
Financial Covenants
Progress Energy's, CP&L's and Florida Power's credit lines and the bank
facility of Progress Genco Ventures, LLC (Genco), a PVI subsidiary, contain
various terms and conditions that could affect the Company's ability to
borrow under these facilities. These include maximum debt to total capital
ratios, interest coverage tests, material adverse change clauses and
cross-default provisions.
All of the credit facilities agreements include a defined maximum total debt
to total capital ratio. As of December 31, 2002, the calculated ratio for
these four companies, pursuant to the terms of the agreements, are as
follows:
Company Maximum Ratio Actual Ratio (b)
----------------------------------- ------------------- ------------------
Progress Energy, Inc. 70% (a) 62.4%
Carolina Power & Light Company 65% 52.7%
Florida Power Corporation 65% 48.6%
Progress Genco Ventures, LLC 40% 24.8%
(a) Progress Energy's maximum debt ratio reduces to 68% effective June 30,
2003.
(b) Indebtedness as defined by the bank agreements includes certain letters
of credit and guarantees which are not recorded on the Consolidated Balance
Sheets.
Progress Energy's 364-day credit facility has a financial covenant for
interest coverage. This covenant requires Progress Energy's EBITDA to
interest expense to be at least 2.5 to 1. For the year ended December 31,
2002, this ratio was 3.43 to 1. Genco's bank facility requires a minimum
1.25 to 1 debt service coverage ratio. For the year ended December 31, 2002,
Genco's debt service coverage was 7.65 to 1.
Material adverse change clause
The credit facilities of Progress Energy, CP&L, Florida Power and Genco
include a provision under which lenders could refuse to advance funds in the
event of a material adverse change in the borrower's financial condition.
Cross-default provisions
Progress Energy's, CP&L's and Florida Power's credit lines include
cross-default provisions for defaults of indebtedness in excess of $10
million. Progress Energy's cross-default provisions only apply to defaults
of indebtedness by Progress Energy and its significant subsidiaries (i.e.
CP&L, FPC, Florida Power, PVI, Progress Fuels and Progress Capital Holdings,
Inc.). CP&L's and Florida Power's cross-default provisions only apply to
defaults of indebtedness by CP&L and Florida Power and their subsidiaries,
respectively, not other affiliates of CP&L and Florida Power. The Genco
credit facility includes a similar provision for defaults by Progress Energy
or PVI.
24
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25
million; these provisions only apply to other obligations of Progress
Energy, not its subsidiaries. In the event that these indenture
cross-default provisions are triggered, the debt holders could accelerate
payment of approximately $4.8 billion in long-term debt. Certain agreements
underlying the Company's indebtedness also limit its ability to incur
additional liens or engage in certain types of sale and leaseback
transactions.
Other restrictions
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Certain
documents restrict the payment of dividends by Progress Energy's
subsidiaries as outlined below.
CP&L's mortgage indenture provides that so long as any first mortgage bonds
are outstanding, cash dividends and distributions on its common stock, and
purchases of its common stock, are restricted to aggregate net income
available for CP&L, since December 31, 1948, plus $3 million, less the
amount of all preferred stock dividends and distributions, and all common
stock purchases, since December 31, 1948. At December 31, 2002, none of
CP&L's retained earnings of $1.3 billion was restricted.
In addition, CP&L's Articles of Incorporation provide that cash dividends on
common stock shall be limited to 75% of net income available for dividends
if common stock equity falls below 25% of total capitalization, and to 50%
if common stock equity falls below 20%. On December 31, 2002, CP&L's common
stock equity was approximately 46.6% of total capitalization.
Florida Power's mortgage indenture provides that it will not pay any cash
dividends upon its common stock, or make any other distribution to the
stockholders, except a payment or distribution out of net income of Florida
Power subsequent to December 31, 1943. At December 31, 2002, none of Florida
Power's retained earnings of $598 million was restricted.
In addition, Florida Power's Articles of Incorporation provide that no cash
dividends or distributions on common stock shall be paid, if the aggregate
amount thereof since April 30, 1944, including the amount then proposed to
be expended, plus all other charges to retained earnings since April 30,
1944, exceed (a) all credits to retained earnings since April 30, 1944, plus
(b) all amounts credited to capital surplus after April 30, 1944, arising
from the donation to Florida Power of cash or securities or transfers
amounts from retained earnings to capital surplus.
Florida Power's Articles also provide that cash dividends on common stock
shall be limited to 75% of net income available for dividends if common
stock equity falls below 25% of total capitalization, and to 50% if common
stock equity falls below 20%. On December 31, 2002, Florida Power's common
stock equity was approximately 50.7% of total capitalization.
Genco is required to hedge 75% of the amount outstanding under its bank
facility through September 2005 and 50% thereafter, pursuant to the term of
the agreement for expansion of its nonregulated generation portfolio. At
December 31, 2002, Genco held interest rate cash flow hedges with a notional
amount of $195 million and a total fair value of $12.3 million liability
position related to this covenant. See additional discussion of interest
rate cash flow hedges in Note 16.
C. Secured Obligations
CP&L's and Florida Power's first mortgage bonds are secured by their
respective mortgage indentures. Each mortgage constitutes a first lien on
substantially all of the fixed properties of the respective company, subject
to certain permitted encumbrances and exceptions. Each mortgage also
constitutes a lien on subsequently acquired property. At December 31, 2002,
CP&L and Florida Power had a total of approximately $3.3 billion of first
mortgage bonds outstanding, including those related to pollution control
obligations. Each mortgage allows the issuance of additional mortgage bonds
upon the satisfaction of certain conditions.
25
Genco obtained a bank facility to be used exclusively for expansion of its
nonregulated generation portfolio. Borrowings under this facility are
secured by the assets in the generation portfolio. The facility is for up to
$310 million, of which $225 million had been drawn as of December 31, 2002.
Borrowings under the facility are restricted for the operations,
construction, repayments and other related charges of the credit facility
for the development projects. Cash held and restricted to operations was
$21.1 million at December 31, 2002, and is included in other current assets.
Cash held and restricted for long-term purposes was $37.1 million at
December 31, 2002 and is included in other assets and deferred debits on the
Consolidated Balance Sheets.
D. Guarantees of Subsidiary Debt
FPC has guaranteed the outstanding debt obligations for two of its wholly
owned subsidiaries, FPC Capital I and Progress Capital Holdings, Inc
(Progress Capital Holdings).
At December 31, 2002 and 2001, Progress Capital Holdings had $223 million
and $273 million, respectively, in medium-term notes outstanding which were
fully guaranteed by FPC (See Note 8). FPC Capital I had $300 million in
mandatorily redeemable securities outstanding at December 31, 2002 and 2001
for which FPC has also guaranteed payment. See Note 9 for additional
discussion of these notes. This debt is recorded on the Company's
accompanying Consolidated Balance Sheets.
E. Hedging Activities
Progress Energy uses interest rate derivatives to adjust the fixed and
variable rate components of its debt portfolio and to hedge cash flow risk
of fixed rate debt to be issued in the future. See discussion of risk
management activities and derivative transactions at Note 16.
9. FPC-Obligated Mandatorily Redeemable Preferred Securities 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 an annual 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 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.
These Preferred Securities are classified as long-term debt on the Company's
Consolidated Balance Sheets.
26
10. 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
CVO liability is adjusted to reflect market price fluctuations. The
liability, included in other liabilities and deferred credits, at December
31, 2002 and 2001, was $13.8 million and $41.9 million, respectively.
11. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption
All of the Company's preferred stock was issued by its subsidiaries and was
not subject to mandatory redemption. Preferred stock outstanding at December
31, 2002 and 2001 consisted of the following (in thousands, except share
data):
Carolina Power & Light Company:
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
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000
$5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00) 24,985
----------
$59,334
----------
Florida Power Corporation:
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
4.40% - 75,000 shares outstanding (redemption price $102.00) 7,500
4.58% - 99,990 shares outstanding (redemption price $101.00) 9,999
4.60% - 39,997 shares outstanding (redemption price $103.25) 4,000
4.75% - 80,000 shares outstanding (redemption price $102.00) 8,000
----------
$33,497
----------
Total Preferred Stock of Subsidiaries $92,831
==========
12. 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. These contingent rentals are not
significant. Rent expense (under operating leases) totaled $57.1 million,
$62.6 million and $26.8 million for 2002, 2001 and 2000, respectively.
Assets recorded under capital leases at December 31 consist of (in
thousands):
2002 2001
--------- ---------
Buildings $ 27,626 $ 27,626
Equipment and other 2,919 12,170
Less: Accumulated amortization (9,422) (8,975)
--------- ---------
$ 21,123 $ 30,821
========= =========
Equipment and other capital lease assets were written down in conjunction
with the impairments of Progress Telecom and Caronet during the third
quarter of 2002 (See Note 7A).
27
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as of
December 31, 2002 are (in thousands):
Capital Leases Operating Leases
--------------- ----------------
2003 $ 3,300 $75,722
2004 3,300 58,750
2005 3,300 35,356
2006 3,300 24,695
2007 3,300 20,185
Thereafter 29,014 78,400
---------------
----------------
$45,514 $293,108
================
Less amount representing imputed interest (17,042)
---------------
Present value of net minimum lease payments
under capital leases $ 28,472
===============
The Company expects to sell Railcar Ltd. during 2003 (See Note 3B). The
operating lease obligations above include $34.2 million, $24.0 million, $6.7
million, $1.5 million, and $1.4 million for the years 2003 through 2007,
respectively, which are attributable to Railcar Ltd. Upon the sale of the
related assets, the Company expects to be relieved of these obligations.
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 for 2003
through 2007 are approximately $11.3 million, $7.7 million, $6.0 million,
$4.8 million and $2.7 million, respectively, with $7.3 million receivable
thereafter. These rentals receivable totals include $10.3 million, $7.0
million, $5.6 million, $4.5 million, and $2.6 million, for the years 2003
through 2007, respectively, and $4.4 million thereafter, which are
attributable to Railcar Ltd. Upon the sale of the related assets, the
Company expects to no longer receive this income.
CP&L and Florida Power are lessors of electric poles and streetlights. Rents
received are contingent upon usage and totaled $80.8 million, $78.4 million
and $27.5 million for 2002, 2001 and 2000, respectively.
13. 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, 2002 and 2001, investments in company-owned life insurance and
other benefit plan assets, with carrying amounts of approximately $149.9
million and $124.3 million, respectively, are included in miscellaneous
other property and investments and approximate fair value due to the short
maturity of the instruments. Other instruments are presented at fair value
in accordance with GAAP. The carrying amount of the Company's long-term
debt, including current maturities, was $10.1 billion and $9.4 billion at
December 31, 2002 and 2001, respectively. The estimated fair value of this
debt, as obtained from quoted market prices for the same or similar issues,
was $11.0 billion and $9.7 billion at December 31, 2002 and 2001,
respectively.
External funds have been established as a mechanism to fund certain costs of
nuclear decommissioning (See Note 1H). These nuclear decommissioning trust
funds are invested in stocks, bonds and cash equivalents. Nuclear
decommissioning trust funds are presented on the Consolidated Balance Sheets
at amounts that approximate fair value. Fair value is obtained from quoted
market prices for the same or similar investments.
14. Common Stock
In November 2002, the Company issued 14.67 million shares of common stock
for net cash proceeds of approximately $600.0 million, which were primarily
used to retire commercial paper. In April 2002, the Company issued 2.5
million shares of common stock, valued at approximately $129.0 million
dollars, in conjunction with the purchase of Westchester Gas Company (See
Note 2B). In August 2001, the Company issued 12.65 million shares of common
stock for net cash proceeds of $488.0 million, which were primarily used to
retire commercial paper. In November 2000, the Company issued 46.5 million
shares of common stock, valued at approximately $1.9 billion, in conjunction
with the FPC acquisition (See Note 2C).
28
As of December 31, 2002, the Company had 52,537,780 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. In July
2002, the Board of Directors authorized meeting the requirements of the
Progress Energy 401(k) Savings and Stock Ownership Plan and the Investor
Plus Stock Purchase Plan with original issue shares. Prior to that
authorization, the Company met the requirements of these stock plans with
issued and outstanding shares held by the Trustee of the Progress Energy
401(k) Savings and Stock Ownership Plan (previously known as the Progress
Energy, Inc. Stock Purchase-Savings Plan) or with open market purchases of
common stock shares, as appropriate. During 2002, the Company issued
approximately 2.1 million shares under these plans for net proceeds of
approximately $87.0 million. The Company continues to meet the requirements
of the restricted stock plan with issued and outstanding shares.
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2002,
there were no significant restrictions on the use of retained earnings.
15. 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 nonregulated 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 was 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, 2002 and 2001, the balances of the utilities' regulatory
assets (liabilities) were as follows (in thousands):
2002 2001
----------- -----------
Deferred fuel costs (included in current assets) $ 183,518 $ 146,652
----------- -----------
Income taxes recoverable through future rates 230,025 236,312
Deferred purchased power contract termination costs 46,601 95,326
Harris Plant deferred costs 16,888 32,476
Loss on reacquired debt 32,979 25,649
Deferred DOE enrichment facilities-related costs (Note 1G) 31,525 39,102
Other postretirement benefits (Note 18C) 11,018 12,207
Other 24,179 22,765
----------- -----------
Total regulatory assets 393,215 463,837
----------- -----------
Nuclear maintenance and refueling (9,601) (346)
Defined benefit retirement plan (Note 18C) (50,988) (234,102)
Emission allowance gains (7,774) (7,494)
Storm reserve (Note 24D) (35,631) (35,527)
Other (15,772) (14,320)
----------- -----------
Total regulatory liabilities (119,766) (291,789)
----------- -----------
Net regulatory assets $ 456,967 $ 318,700
=========== ===========
29
NCNG is allowed to recover the costs of gas purchased for resale through
customer rates. NCNG was in an overrecovery position as of December 31, 2002
and 2001. The NCNG liability of $12.7 million as of December 31, 2002 and
$4.5 million as of December 31, 2001 is included in liabilities of
discontinued operations.
Except for portions of deferred fuel, all regulatory 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. Florida Power Rate Case Settlement
Florida Power's retail rates are set by the FPSC, while its wholesale rates
are governed by FERC. Florida Power's last general retail rate case was
approved in 1992 and allowed a 12% regulatory return on equity with an
allowed range between 11% and 13%. Florida Power previously operated under
an agreement committing several parties not to seek any reduction in its
base rates or authorized return on equity. That agreement expired on June
30, 2001. The FPSC initiated a rate proceeding in 2001 regarding Florida
Power's future base rates. On March 27, 2002, the parties in Florida Power's
rate case entered into a Stipulation and Settlement Agreement (the
Agreement) related to retail rate matters. The Agreement was approved by the
FPSC on April 23, 2002. The Agreement is generally effective from May 1,
2002 through December 31, 2005; provided, however, that if Florida Power's
base rate earnings fall below a 10% return on equity, Florida Power may
petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues
from the sale of electricity by an annual amount of $125 million. The
Agreement also provides that Florida Power will operate under a Revenue
Sharing Incentive Plan (the Plan) through 2005, and thereafter until
terminated by the FPSC, that establishes annual revenue caps and sharing
thresholds. The Plan provides that retail base rate revenues between the
sharing thresholds and the retail base rate revenue caps will be divided
into two shares - a 1/3 share to be received by Florida Power's
shareholders, and a 2/3 share to be refunded to Florida Power's retail
customers; provided, however, that for the year 2002 only, the refund to
customers will be limited to 67.1% of the 2/3 customer share. The retail
base rate revenue sharing threshold amounts for 2002 were $1.296 billion and
will increase $37 million each year thereafter. The Plan also provides that
all retail base rate revenues above the retail base rate revenue caps
established for each year will be refunded to retail customers on an annual
basis. For 2002, the refund to customers was limited to 67.1% of the retail
base rate revenues that exceed the 2002 cap. The retail base revenue cap for
2002 was $1.356 billion and will increase $37 million each year thereafter.
Any amounts above the retail base revenue caps will be refunded 100% to
customers. As of December 31, 2002, $4.7 million was accrued and will be
refunded to customers by March 2003.
The Agreement also provides that beginning with the in-service date of
Florida Power's Hines Unit 2 and continuing through December 31, 2005,
Florida Power will be allowed to recover through the fuel cost recovery
clause a return on average investment and depreciation expense for Hines
Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel
savings over the recovery period. Hines Unit 2 is a 516 MW combined-cycle
unit under construction and currently scheduled for completion in late 2003.
Additionally, the Agreement provided that Florida Power would effect a
mid-course correction of its fuel cost recovery clause to reduce the fuel
factor by $50 million for 2002. The fuel cost recovery clause will operate
as it normally does, including, but not limited to any additional mid-course
adjustments that may become necessary, and the calculation of true-ups to
actual fuel clause expenses.
Florida Power will suspend accruals on its reserves for nuclear
decommissioning and fossil dismantlement through December 31, 2005.
Additionally, for each calendar year during the term of the Agreement,
Florida Power will reduce depreciation expense by $62.5 million, and may, at
its option, record up to an equal annual amount as an offsetting accelerated
depreciation expense. In addition, Florida Power is authorized, at its
discretion, to accelerate the amortization of certain regulatory assets over
the term of the Agreement. Florida Power recorded no accelerated
depreciation or amortization expense for the year ended December 31, 2002.
30
Under the terms of the Agreement, Florida Power agreed to continue the
implementation of its four-year Commitment to Excellence Reliability Plan
and expects to achieve a 20% improvement in its annual System Average
Interruption Duration Index by no later than 2004. If this improvement level
is not achieved for calendar years 2004 or 2005, Florida Power will provide
a refund of $3 million for each year the level is not achieved to 10% of its
total retail customers served by its worst performing distribution feeder
lines.
Per the Agreement, Florida Power was required to refund to customers $35
million of revenues Florida Power collected during the interim period since
March 13, 2001. This one-time retroactive revenue refund was recorded in the
first quarter of 2002 and was returned to retail customers over an
eight-month period ended December 31, 2002. Any additional refunds under the
Agreement are recorded when they become probable.
C. 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. On June 14, 2002, the NCUC approved modification of CP&L's ongoing
accelerated cost recovery of its nuclear generating assets. Effective
January 1, 2003, the NCUC will no longer require annual minimum accelerated
depreciation. The aggregate minimum and maximum amounts of accelerated
depreciation, $415 million and $585 million, respectively, are unchanged
from the original NCUC order. The date by which the minimum amount must be
depreciated was extended from December 31, 2004 to December 31, 2009. On
October 29, 2002, the SCPSC approved similar modifications. The order was
effective November 1, 2002, and the aggregate minimum and maximum of $115
million and $165 million established for accelerated cost recovery by the
SCPSC is unchanged. The accelerated cost recovery of these assets resulted
in additional depreciation expense of approximately $53 million, $75 million
and $275 million in 2002, 2001 and 2000, respectively. 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. Total accelerated depreciation recorded
through December 31, 2002 was $326 million for the North Carolina
jurisdiction and $77 million for the South Carolina jurisdiction.
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 offset
accelerated depreciation expense against emission allowance expense by
approximately $5.8 million in 2002. CP&L did not offset accelerated
depreciation expense against emission allowance expense in 2001. 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. See Note 24E regarding the
North Carolina rate freeze and accelerated recovery of environmental costs
beginning January 1, 2003.
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.
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. On May 3, 2002, NCNG withdrew the
application, based upon the NCUC Public Staff's and other parties'
interpretation of the order approving the merger of CP&L and NCNG that such
a case was not permitted until 2003. On May 16, 2002, NCNG filed a request
to increase its margin rates and rebalance its rates with the NCUC,
requesting an annual rate increase of $4.1 million to recover costs
associated with specific system improvements. On September 23, 2002, the
NCUC issued its order approving the $4.1 million rate increase. The rate
increase was effective October 1, 2002.
In conjunction with the FPC merger, CP&L reached a settlement with the
Public Staff of the NCUC in which it agreed to provide credits to its
non-real time pricing customers in the amounts of $3.0 million in 2002, $4.5
million in 2003, $6.0 million in 2004 and $6.0 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.
31
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
reduce 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.
In February 2003, Florida Power petitioned the FPSC to increase its fuel
factors due to continuing increases in oil and natural gas commodity prices.
The crisis in the Middle East along with the Venezuelan oil workers' strike
have put upward pressure on commodity prices that were not anticipated by
Florida Power when fuel factors for 2003 were approved by the FPSC in
November 2002. If Florida Power's petition is approved, the increase would
go into effect April 1, 2003.
D. Regional Transmission Organizations
In early 2000 FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions
that RTOs must meet, including independent transmission service. As a result
of Order 2000, Florida Power, along with Florida Power & Light Company and
Tampa Electric Company, filed with FERC, in October 2000, an application for
approval of a Grid Florida RTO. On March 28, 2001, FERC issued an order
provisionally approving GridFlorida. CP&L, along with Duke Energy
Corporation and South Carolina Electric & Gas Company, filed with FERC, for
approval of a GridSouth RTO. On July 12, 2001, FERC issued an order
provisionally approving GridSouth. However, in July 2001, FERC issued orders
recommending that companies in the Southeast engage in a mediation to
develop a plan for a single RTO for the Southeast. Florida Power and CP&L
participated in the mediation. FERC has not issued an order specifically on
this mediation. On July 31, 2002, FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity Market Design (SMD
NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would
materially alter the manner in which transmission and generation services
are provided and paid for. Florida Power and CP&L, as subsidiaries of
Progress Energy, filed comments on November 15, 2002 and supplement comments
on January 10, 2003. On January 15, 2003 FERC announced the issuance of a
White Paper on SMD to be released in April 2003. Florida Power and CP&L, as
subsidiaries of Progress Energy, plan to file comments on the White Paper.
FERC has also indicated that it expects to issue final rules during the
summer 2003. The Company cannot predict the outcome of these matters or the
effect that they may have on the GridFlorida and GridSouth proceedings
currently ongoing before the FERC. The Company has $28.4 million and an
insignificant amount invested in GridSouth and GridFlorida, respectively, at
December 31, 2002. It is unknown what impact the future proceedings will
have on the Company's earnings, revenues or prices.
16. Risk Management Activities and Derivatives Transactions
Under its risk management policy, the Company may use a variety of
instruments, including swaps, options and forward contracts, to manage
exposure to fluctuations in commodity prices and interest rates. Such
instruments contain credit risk if the counterparty fails to perform under
the 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.
A. Commodity Contracts - General
Most of the Company's commodity contracts are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
B. Commodity Derivatives - Cash Flow Hedges
The Company held natural gas and oil cash flow hedging instruments at
December 31, 2002. The objective for holding these instruments is to manage
a portion of the market risk associated with fluctuations in the price of
natural gas and oil on the Company's forecasted sales of natural gas and oil
production. As of December 31, 2002, the Company is hedging exposures to the
price variability of these commodities for contracts maturing through
December 2004.
The total fair value of these instruments at December 31, 2002 was a $10.2
million liability position. The ineffective portion of commodity cash flow
hedges was not material in 2002. As of December 31, 2002, $5.0 million of
after-tax deferred losses in accumulated other comprehensive income (OCI)
are expected to be reclassified to earnings during the next 12 months as the
hedged transactions occur. Due to the volatility of the commodities markets,
the value in OCI is subject to change prior to its reclassification into
earnings.
32
C. Commodity Derivatives - Economic Hedges and Trading
Nonhedging derivatives, primarily electricity and natural gas contracts, are
entered into for trading purposes and for economic hedging purposes. While
management believes the economic hedges mitigate exposures to fluctuations
in commodity prices, these instruments are not designated as hedges for
accounting purposes and are monitored consistent with trading positions. The
Company manages open positions with strict policies that limit its exposure
to market risk and require daily reporting to management of potential
financial exposures. Gains and losses from such contracts were not material
during 2002, 2001 or 2000, and the Company did not have material outstanding
positions in such contracts at December 31, 2002 or 2001.
D. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
The Company manages its interest rate exposure in part by maintaining its
variable-rate and fixed rate-exposures within defined limits. In addition,
the Company also enters into financial derivative instruments, including,
but not limited to, interest rate swaps and lock agreements to manage and
mitigate interest rate risk exposure.
The Company uses cash flow hedging strategies to hedge variable interest
rates on long-term debt and to hedge interest rates with regard to future
fixed-rate debt issuances. At December 31, 2002, the Company held an
interest rate cash flow hedge, with a notional amount of $35.0 million,
related to an anticipated 2003 issuance of fixed-rate debt and held interest
rate cash flow hedges, with a varying notional amount and maximum of $195.0
million, related to variable-rate debt. The total fair value of these hedges
at December 31, 2002 was a $12.8 million liability position. As of December
31, 2002, $7.8 million of after-tax deferred losses in OCI, including
amounts in OCI related to terminated hedges, are expected to be reclassified
to earnings during the next 12 months as the hedged interest payments occur.
Due to the volatility of interest rates, the value in OCI is subject to
change prior to its reclassification into earnings. At December 31, 2001,
the Company had open interest rate cash flow hedges with notional amounts
totaling $500.0 million and a total fair value of $18.5 million liability
position.
The Company uses fair value hedging strategies to manage its exposure to
fixed interest rates on long-term debt. At December 31, 2002, the Company
had open interest rate fair value hedges with notional amounts totaling
$350.0 million and a total fair value of $5.2 million asset position. In
addition, the Company initiated and terminated interest rate fair value
hedges on long-term debt in 2002, resulting in total deferred hedging gains
of approximately $35.2 million reflected in long-term debt, which are being
amortized over periods ending in 2006 and 2007 coinciding with the maturity
of the related debt instruments.
The notional amounts of interest rate derivatives 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.
17. Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the
provisions of APB Opinion No. 25 as allowed by SFAS Nos. 123 and 148.
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 Progress Energy 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
33
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.
Also, beginning in 2002, the dividends paid on ESOP shares which are either
paid directly to participants or used to purchase additional shares which
are then allocated to participants are fully deductible for income tax
purposes.
There were 4,616,400 and 5,199,388 ESOP suspense shares at December 31, 2002
and 2001, respectively, with a fair value of $200.1 million and $234.1
million, respectively. ESOP shares allocated to plan participants totaled
13,554,283 and 14,088,173 at December 31, 2002 and 2001, 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, with shares released from the ESOP suspense
account and with newly issued shares. Matching and incentive cost met with
shares released from the suspense account totaled approximately $20.3
million, $18.2 million and $15.6 million for the years ended December 31,
2002, 2001 and 2000, 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 and 2002 Equity
Incentive Plan, amended and restated as of July 10, 2002, the Company may
grant options to purchase shares of common stock to directors, officers and
eligible employees. Generally, options granted to employees, vest one-third
per year with 100% vesting at the end of year three and options granted to
directors vest 100% at the end of one year. The options expire ten 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.
Compensation expense 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 stock option grants.
The proforma information presented in Note 1U regarding net income and
earnings per share is required by SFAS No. 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 proforma amounts
presented in Note 1U have been determined as if the Company had accounted
for its employee stock options under SFAS No. 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:
2002 2001
----------------------
Risk-free interest rate (%) 4.14% 4.83%
Dividend yield (%) 5.20% 5.21%
Volatility factor (%) 24.98% 26.47%
Weighted-average expected life of the options (in years) 10 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 options outstanding as of December 31, 2002 and 2001 had a
weighted-average remaining contractual life of 9.32 and 9.75 years,
respectively, and had exercise prices that ranged from $41.97 to $51.85.
There were no options outstanding at December 31, 2000. At December 31,
2002, 92,400 outstanding shares were antidilutive for purposes of
calculating diluted earnings per share. All options outstanding at December
31, 2001 were antidilutive. As of December 31, 2002, no options have expired
or been exercised. The tabular information for the option activity is as
follows:
34
2002 2002 2001 2001
----------- ------------------ ----------- ---------------
Number of Weighted-Average Number of Weighted-
Options Exercise Price Options Average
Exercise Price
Options outstanding, January 1 2,328,855 $43.49 - -
Granted 2,893,650 $42.34 2,353,155 $43.49
Forfeited (65,310) $43.71 (24,300) $43.49
Options outstanding, December 31 5,157,195 $42.84 2,328,855 $43.49
Options exercisable at December 31,
with a remaining contractual life of
8.75 years 754,538 $43.49 - -
Weighted-average grant date fair value
of options granted during the year $6.83 $8.05
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 and were continued under the Company's
2002 Equity Incentive Plan, as amended and restated as of July 10, 2002.
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 generally
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 $44.27, $41.86 and $36.97 in
2002, 2001 and 2000, 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:
2002 2001 2000
---------- ----------- ------------
Beginning balance 674,511 653,344 331,900
Granted 365,920 113,651 359,844
Vested (75,200) (70,762) -
Forfeited (15,051) (21,722) (38,400)
---------- ----------- ------------
Ending balance 950,180 674,511 653,344
========== =========== ============
The total amount expensed for other stock-based compensation plans was $16.7
million, $14.3 million and $15.6 million in 2002, 2001 and 2000,
respectively.
35
18. Postretirement Benefit Plans
A. Pension Benefits
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):
2002 2001 2000
--------------- --------------- ---------------
Expected return on plan assets $ (161,181) $ (169,329) $ (87,628)
Service cost 45,414 31,863 22,123
Interest cost 105,646 96,200 56,924
Amortization of transition obligation 106 125 125
Amortization of prior service (benefit) cost 306 (1,325) (1,314)
Amortization of actuarial (gain) loss 2,050 (4,989) (5,721)
--------------- --------------- ---------------
Net periodic pension benefit (7,659) (47,455) (15,491)
Additional benefit recognition (Note 18C) (7,614) (16,464) (3,401)
--------------- --------------- ---------------
Net periodic pension benefit recognized $ (15,273) $(63,919) $ (18,892)
=============== =============== ===============
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.
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):
2002 2001
------------ ------------
Projected benefit obligation at January 1 $ 1,390,737 $ 1,376,859
Interest cost 105,646 96,200
Service cost 45,414 31,863
Benefit payments (91,114) (86,010)
Actuarial loss 242,898 13,164
Plan amendments - 20,882
Acquisition adjustment (Note 2C) - (62,221)
------------ ------------
Projected benefit obligation at December 31 1,693,581 1,390,737
Fair value of plan assets at December 31 1,363,943 1,677,630
------------ ------------
Funded status (329,638) 286,893
Unrecognized transition obligation 264 370
Unrecognized prior service cost 5,040 5,346
Unrecognized actuarial loss 741,885 111,600
Minimum pension liability adjustment (496,904) -
------------ ------------
Prepaid (accrued) pension cost at December 31, net (Note 18C) $ (79,353) $ 404,209
============ ============
36
The net accrued pension cost of $79.4 million at December 31, 2002 is
recognized in the accompanying Consolidated Balance Sheets as prepaid
pension cost of $60.2 million, accrued benefit cost of $139.6 million, of
which $130.7 is included in other liabilities and deferred credits and $8.9
million is included in liabilities of discontinued operations. 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
$487.6 million, accrued benefit cost of $85.4 million, which is included in
other liabilities and deferred credits, and for NCNG prepaid pension cost,
$2.0 million is included in assets of discontinued operations. The defined
benefit plans with accumulated benefit obligations in excess of plan assets
had projected benefit obligations totaling $1.51 billion and $85.1 million
at December 31, 2002 and 2001, respectively. Those plans had accumulated
benefit obligations totaling $1.35 billion and $83.9 million at December 31,
2002 and 2001, respectively, plan assets totaling $1.22 billion at December
31, 2002 and no plan assets at December 31, 2001.
Due to a combination of decreases in the fair value of plan assets and a
decrease in the discount rate used to measure the pension obligation, a
minimum pension liability adjustment of $496.9 million was recorded at
December 31, 2002. This adjustment resulted in a charge of $5.3 million to
intangible assets, included in other assets and deferred debits in the
accompanying Consolidated Balance Sheets, a $178.3 million charge to a
pension-related regulatory liability (see Note 18C) and a pre-tax charge of
$313.3 million to accumulated other comprehensive loss, a component of
common stock equity.
Reconciliations of the fair value of pension plan assets are (in thousands):
2002 2001
------------ ------------
Fair value of plan assets at January 1 $ 1,677,630 $ 1,843,410
Actual return on plan assets (228,256)
(84,254)
Benefit payments (91,114) (86,010)
Employer contributions 5,683 4,484
------------ ------------
Fair value of plan assets at December 31 $ 1,363,943 $ 1,677,630
============ ============
The weighted-average discount rate used to measure the pension obligation
was 6.6% and 7.5% in 2002 and 2001, respectively. The weighted-average rate
of increase in future compensation for non-bargaining unit employees used to
measure the pension obligation was 4.0% in 2002, 2001 and 2000. The
corresponding rate of increase in future compensation for bargaining unit
employees was 3.5% in 2002, 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 2002, 2001 and 2000.
B. Retiree Health and Life Insurance Benefits
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):
2002 2001 2000
----------- ----------- -----------
Expected return on plan assets $ (4,565) $(4,651) $ (4,045)
Service cost 13,099 13,231 10,067
Interest cost 31,876 28,414 15,446
Amortization of prior service cost 506 319 107
Amortization of transition obligation 3,066 4,701 5,878
Amortization of actuarial (gain) loss 656 (592) (819)
----------- ----------- -----------
Net periodic OPEB cost 44,638 41,422 26,634
Additional cost recognition (Note 18C) 1,863 3,461 202
----------- ----------- -----------
Net periodic OPEB cost recognized $ 46,501 $ 44,883 $ 26,836
=========== =========== ===========
37
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):
2002 2001
----------- -----------
OPEB obligation at January 1 $ 400,944 $ 374,923
Interest cost 31,876 28,414
Service cost 13,099 13,231
Benefit payments (24,144) (17,207)
Actuarial loss 91,842 27,428
Plan amendment - (25,845)
---------- -----------
OPEB obligation at December 31 513,617 400,944
Fair value of plan assets at December 31 52,354 55,529
---------- -----------
Funded status (461,263) (345,415)
Unrecognized transition obligation 30,063 33,129
Unrecognized prior service cost 7,169 7,675
Unrecognized actuarial loss 106,686 6,429
---------- -----------
Accrued OPEB cost at December 31 (Note 18C) $(317,345) $(298,182)
========== ===========
The accrued OPEB cost is included in other liabilities and deferred credits
in the accompanying Consolidated Balance Sheets.
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2002 2001
--------- ---------
Fair value of plan assets at January 1 $ 55,529 $ 54,642
Actual return on plan assets (4,506) (444)
Employer contribution 25,475 18,538
Benefits paid (24,144) (17,207)
--------- ---------
Fair value of plan assets at December 31 $ 52,354 $ 55,529
========= =========
The assumptions used to measure the OPEB obligation and determine the net
periodic OPEB cost are:
2002 2001 2000
Weighted-average long-term rate of return on plan assets 8.20% 8.70% 9.20%
Weighted-average discount rate 6.60% 7.50% 7.50%
Initial medical cost trend rate for pre-Medicare benefits 7.50% 7.50% 7.2% - 7.5%
Initial medical cost trend rate for post-Medicare benefits 7.50% 7.50% 6.2% - 7.5%
Ultimate medical cost trend rate 5.25% 5.0% 5.0% - 5.3%
Year ultimate medical cost trend rate is achieved 2009 2008 2005-2009
38
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 2002 would increase by $7.0 million, and
the OPEB obligation at December 31, 2002, would increase by $50.8 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 2002
would decrease by $6.0 million and the OPEB obligation at December 31, 2002,
would decrease by $46.2 million.
C. FPC Acquisition
During 2000, the Company completed the acquisition of FPC (See Note 2C).
FPC's pension and OPEB liabilities, assets and net periodic costs are
reflected in the above information as appropriate. 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 accrued OPEB cost reflected in the table above has a
corresponding regulatory asset at December 31, 2002 and 2001 (see Note 15A).
In addition, a portion of the prepaid pension cost reflected in the table
above has a corresponding regulatory liability. Pursuant to its rate
treatment, Florida Power recognized additional periodic pension credits and
additional periodic OPEB costs, as indicated in the net periodic cost
information above.
19. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average number of
common shares outstanding. Diluted earnings per share includes the effect of
the non-vested portion of restricted stock awards and the effect of stock
options outstanding.
A reconciliation of the weighted-average number of common shares outstanding
for basic and dilutive purposes is as follows (in thousands):
2002 2001 2000
------------- ------------ ------------
Weighted-average common shares - basic 217,247 204,683 157,169
Restricted stock awards 766 664 455
Stock options 153 - -
------------- ------------ ------------
Weighted-average shares - fully dilutive 218,166 205,347 157,624
============= ============ ============
There are no adjustments to net income or to income from continuing
operations between the calculations of basic and fully diluted earnings per
common share. 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
4.8 million, 5.4 million and 5.7 million for the years ended December 31,
2002, 2001 and 2000, respectively.
20. 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.
39
Accumulated deferred income tax (assets) liabilities at December 31 are (in
thousands):
2002 2001
------------ ------------
Accelerated depreciation and property cost differences $ 1,657,410 $ 1,748,646
Deferred costs, net (33,485) 79,819
Federal income tax credit carry forward (474,545) (278,773)
Minimum pension liability adjustment (117,064) -
Miscellaneous other temporary differences, net (106,650) (149,615)
Valuation allowance 46,779 35,270
------------ ------------
Net accumulated deferred income tax liability $ 972,445 $ 1,435,347
============ ============
Total deferred income tax liabilities were $2.50 billion and $2.64 billion
at December 31, 2002 and 2001, respectively. Total deferred income tax
assets were $1.53 billion and $1.20 billion at December 31, 2002 and 2001,
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 federal income tax credit carry forward at December 31, 2002, consists
of $451.6 million of alternative minimum tax credit with an indefinite carry
forward period and $22.9 million of general business credit with a carry
forward period that will begin to expire in 2020.
The Company established valuation allowances of $11.5 million, $24.4 million
and $10.9 million during 2002, 2001 and 2000, respectively, due to the
uncertainty of realizing certain future state tax benefits. The Company
believes it is more likely than not that the results of future operations
will generate sufficient taxable income to allow for the utilization of the
remaining deferred tax assets.
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
2002 2001 2000
---------- ---------- -----------
Effective income tax rate (40.0)% (40.0)% 29.1%
State income taxes, net of federal benefit (8.2) (7.7) (4.7)
AFUDC amortization (5.2) (5.0) (5.2)
Federal tax credits 78.0 94.5 12.3
Goodwill amortization and write-offs - (11.4) (0.5)
Investment tax credit amortization 4.7 5.9 4.2
ESOP dividend deduction 3.8 1.9 1.0
Interpath investment impairment - (2.1) -
Other differences, net 1.9 (1.1) (1.2)
---------- ---------- -----------
Statutory federal income tax rate 35.0% 35.0% 35.0%
========== ========== ===========
Income tax expense (benefit) applicable to continuing operations is
comprised of (in thousands):
2002 2001 2000
----------- ----------- ----------
Current - federal $ 194,914 $ 183,548 $ 247,991
state 67,785 52,144 59,832
Deferred - federal (378,939) (356,919) (82,966)
state (23,101) (10,411) (10,414)
Investment tax credit (18,467) (22,700) (17,941)
----------- ----------- ----------
Total income tax expense (benefit) $ (157,808) $ (154,338) $ 196,502
=========== =========== ==========
40
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. Total Section 29 credits generated to
date (including FPC prior to its acquisition by the Company) are
approximately $897.2 million. 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.
One of the Company's synthetic fuel entities, Colona Synfuel Limited
Partnership, L.L.L.P. (Colona), is being audited by the IRS. The audit of
Colona was expected. The Company is audited regularly in the normal course
of business as are most similarly situated companies. The Company (including
FPC prior to its acquisition by the Company) has been allocated
approximately $251 million in tax credits to date for this synthetic fuel
entity. As provided for in contractual arrangements pertaining to Progress
Energy's purchase of Colona, the Company has begun escrowing quarterly
royalty payments owed to an unaffiliated entity until final resolution of
the audit.
In September 2002, all of Progress Energy's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS's Pre-Filing
Agreement (PFA) program. The PFA program allows taxpayers to voluntarily
accelerate the IRS exam process in order to seek resolution of specific
issues. Either the Company or the IRS can withdraw from the program at any
time, and issues not resolved through the program may proceed to the next
level of the IRS exam process. While the ultimate outcome is uncertain, the
Company believes that participation in the PFA program will likely shorten
the tax exam process.
In management's opinion, Progress Energy is complying with all the necessary
requirements to be allowed such credits and believes it is likely, although
it cannot provide certainty, that it will prevail if challenged by the IRS
on any credits taken.
21. Other Income and Other Expense
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items as
discussed below. The components of other, net as shown on the Consolidated
Statements of Income for the years ended December 31 are as follows (in
thousands):
41
2002 2001 2000
------------ ------------- ------------
Other income
Net financial trading gain (loss) $ (1,942) $ (696) $ 15,603
Net energy purchased for resale 1,540 2,786 2,260
Nonregulated energy and delivery services income 28,754 29,183 26,225
Contingent value obligation unrealized gain (Note 10) 28,109 - 8,876
Investment gains 30,218 2,500 6,722
AFUDC equity 8,739 8,842 13,568
Other 31,174 16,444 12,828
------------- ------------- -------------
Total other income $ 126,592 $ 59,059 $ 86,082
------------- ------------- -------------
Other expense
Nonregulated energy and delivery services expenses 28,766 34,734 25,459
Donations 21,302 23,035 9,397
Investment losses 18,235 4,365 6,672
Contingent value obligation unrealized loss (Note 10) - 1,479 -
Other 24,485 23,885 29,131
------------- ------------- -------------
Total other expense $ 92,788 $ 87,498 $ 70,659
Other, net $ 33,804 $ (28,439) $ 15,423
============= ============= =============
Net financial trading gain (loss) represents non-asset-backed trades of
electricity and gas. Nonregulated energy and delivery services include power
protection services and mass market programs (surge protection, appliance
services and area light sales) and delivery, transmission and substation
work for other utilities.
22. Joint Ownership of Generating Facilities
CP&L and Florida Power hold undivided ownership interests in certain jointly
owned generating facilities. 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. The co-owner of P11 has exclusive rights
to the output of the unit during the months of June through September.
Florida Power has that right for the remainder of the year.
CP&L's and Florida Power's ownership interests in the jointly owned
generating facilities are listed below with related information as of
December 31, 2002 and 2001 (dollars in thousands):
2002
Company Construction
Ownership Plant Accumulated Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Decommissioning Progress
---------- -------- -------- ---------- ------------ --------------- -----------
CP&L Mayo Plant 83.83% $ 464,202 $ 239,971 $ - $ 14,089
CP&L Harris Plant 83.83% 3,159,946 1,432,245 95,643 6,117
CP&L Brunswick Plant 81.67% 1,476,534 867,530 339,521 26,436
CP&L Roxboro Unit 4 87.06% 316,491 138,408 - 8,079
Florida Power Crystal River Unit 3 91.78% 777,141 504,417 396,868 27,907
Florida Power Intercession Unit P-11 66.67% 22,090 5,232 - 3,987
42
2001
Company Construction
Ownership Plant Accumulated Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Decommissioning Progress
---------- -------- -------- ---------- ------------ --------------- -----------
CP&L Mayo Plant 83.83% $ 460,026 $ 230,630 $ - $ 7,116
CP&L Harris Plant 83.83% 3,154,183 1,321,694 93,637 14,416
CP&L Brunswick Plant 81.67% 1,427,842 828,480 339,945 41,455
CP&L Roxboro Unit 4 87.06% 309,032 126,007 - 7,881
Florida Power Crystal River Unit 3 91.78% 773,835 469,840 416,995 25,723
Florida Power Intercession Unit P-11 66.67% 22,302 4,583 - 94
In the table above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Harris Plant.
23. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows (in
thousands):
2002 2001
------------ -------------
Loss on cash flow hedges $ (42,236) $(30,623)
Minimum pension liability adjustments (192,385) -
Foreign currency translation and other (3,141) (1,557)
------------ -------------
Total accumulated other comprehensive loss $(237,762) $(32,180)
============ =============
24. 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 $33 million. These
contractual purchases totaled $35.9 million, $33.3 million and $33.9 million
for 2002, 2001 and 2000, 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, 2002 and 2001, CP&L had deferred purchased capacity
costs, including carrying costs accrued on the deferred balances, of $16.9
million and $32.5 million, respectively. Increased purchases (which are not
being deferred for future recovery) resulting from the 1993 agreement with
Power Agency were approximately $32.2 million, $28.6 million and $26.0
million for 2002, 2001 and 2000, 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 $58.6 million, $62.8 million and $61.0 million for 2002, 2001 and 2000,
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 2021 with an original minimum annual payment of
approximately $16 million, primarily representing capital-related capacity
costs. A separate long-term agreement for additional power from Broad River
43
commenced June 1, 2002. This agreement provided for the additional purchase
of approximately 300 megawatts of capacity through 2022 with an original
minimum annual payment of approximately $16 million representing
capital-related capacity costs. Total purchases under the Broad River
agreements amounted to $37.7 million and $21.2 million in 2002 and 2001,
respectively.
Florida Power has long-term contracts for approximately 473 megawatts of
purchased power with other utilities, including a contract with The Southern
Company for approximately 413 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, for both energy and
capacity, under these agreements amounted to $159.3 million, $111.7 million
and $104.5 million for 2002, 2001 and 2000, respectively. Total capacity
payments were $50.5 million, $54.1 million and $54.0 million for 2002, 2001
and 2000, respectively. Minimum purchases under these contracts,
representing capital-related capacity costs, are approximately $50 million
annually through 2005 and $30 million annually for 2006 and 2007.
Both CP&L and Florida Power have ongoing purchased power contracts with
certain cogenerators (qualifying facilities) with expiration dates ranging
from 2003 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. Capacity
payments are subject to the qualifying facilities meeting certain contract
performance obligations. Florida Power's total capacity purchases under
these contracts, amounted to $231.7 million, $225.8 million and $226.4
million for 2002, 2001 and 2000, respectively. Minimum expected future
capacity payments under these contracts as of December 31, 2002 are $246.8
million, $257.4 million, $268.7 million, $279.7 million and $289.4 million
for 2003 through 2007, 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 $144.5 million in 2002,
$145.1 million in 2001 and $168.4 million in 2000.
Florida Power and CP&L have entered into various long-term contracts for
coal, gas and oil requirements of their generating plants. Payments under
these commitments were $1.9 billion, $1.7 billion and $678.8 million for
2002, 2001 and 2000, respectively. Estimated annual payments for firm
commitments of fuel purchases and transportation costs under these contracts
are approximately $1.7 billion, $1.1 billion, $913.8 million, $907.7 million
and $850.6 million for 2003 through 2007, 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), each of approximately $114.3 million and
$134.3 million at December 31, 2002 and 2001, respectively, representing the
minimum amounts due through 2007, discounted at 6.05%. As of December 31,
2002 and 2001, the portions of the asset and liability recorded that were
classified as current were $23.8 million and $25.8 million, respectively.
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 paid under these agreements were
approximately $51.4 million in 2002, $45.8 million in 2001 and $43.1 million
in 2000.
The Company has entered into a joint venture to build a 750-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 in early 2005. In conjunction with the
NCNG divestiture, the Company expects to sell its interest in the venture to
Piedmont Natural Gas, Inc. by summer 2003, subject to receipt of required
regulatory approvals (See Note 3A).
44
C. Guarantees
As a part of normal business, Progress Energy and certain subsidiaries enter
into various agreements providing financial or performance assessments to
third parties. Such agreements include guarantees, stand-by letters of
credit and surety bonds. These agreements are entered into primarily to
support or enhance the creditworthiness otherwise attributed to a subsidiary
on a stand-alone basis, thereby facilitating the extension of sufficient
credit to accomplish the subsidiaries' intended commercial purposes.
At December 31, outstanding guarantees are summarized as follows (in
millions):
2002 2001
------------ -----------
Guarantees supporting nonregulated portfolio expansion
and energy marketing and trading activities $ 329.0 $ 23.0
Standby letters of credit 48.2 29.2
Surety bonds 106.8 52.1
Other guarantees 18.6 39.8
------------ -----------
Total $ 502.6 $ 144.1
============ ===========
Guarantees Supporting Nonregulated Portfolio Expansion and Energy Marketing
and Trading Activities
Progress Energy has issued approximately $317.0 million of guarantees on
behalf of PVI and its subsidiaries for obligations under power purchase
agreements, tolling agreements, gas agreements, construction agreements and
trading operations. Approximately $145.0 million of these commitments relate
to certain guarantee agreements issued to support obligations related to
PVI's expansion of its nonregulated generation portfolio.
The remaining $172.0 million of these new commitments issued by Progress
Energy are guarantees issued to support PVI's energy marketing and trading
functions. The majority of the marketing and trading contracts supported by
the guarantees contain language regarding downgrade events, ratings
triggers, monthly netting of exposure and/or payments and offset provisions
in the event of a default. Based upon the amount of trading positions
outstanding at December 31, 2002, if the Company's ratings were to decline
below investment grade, the Company would have to deposit cash or provide
letters of credit or other cash collateral for approximately $13.7 million
for the benefit of the Company's counterparties.
In addition, PVI issued a $12.0 million guarantee related to expansion of
the portfolio. These guarantees ensure performance under generation
construction and operating agreements.
Standby Letters of Credit
The Company has issued stand-by letters of credit to financial institutions
for the benefit of third parties that have extended credit to the Company
and certain subsidiaries. These letters of credit have been issued primarily
for the purpose of supporting payments of trade payables, securing
performance under contracts and lease obligations and self-insurance for
workers compensation. If a subsidiary does not pay amounts when due under a
covered contract, the counterparty may present its claim for payment to the
financial institution, which will in turn request payment from the Company.
Any amounts owed by the Company's subsidiaries are reflected in the
accompanying Consolidated Balance Sheets.
Surety Bonds
At December 31, 2002, the Company had $106.8 million in surety bonds
purchased primarily for purposes such as providing worker compensation
coverage and obtaining licenses, permits and rights-of-way. To the extent
liabilities are incurred as a result of the activities covered by the surety
bonds, such liabilities are included in the accompanying Consolidated
Balance Sheets.
45
Other Guarantees
The Company has other guarantees outstanding related primarily to prompt
performance payments, lease obligations, and other payments subject to
contingencies.
As of December 31, 2002, management does not believe conditions are likely
for performance under these agreements.
D. 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 its 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 CR3 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 $31.4 million with respect to the primary
coverage, $32.5 million with respect to the decontamination, decommissioning
and excess property coverage, and $22.2 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, 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
decontaminate, 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 $9.55 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
$300 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. Congress is expected to approve revisions to the
Price Anderson Act in the first quarter of 2003, that will include increased
limits and assessments per reactor owned. 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 $300 million. The second level
of coverage obtained through the assessments discussed above would continue
to apply to losses exceeding $300 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 (See Note
15A).
46
E. Claims and uncertainties
1. The Company is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
both electric utilities and the gas utility have some connection. In this
regard, both electric utilities and the gas utility and other potentially
responsible parties, are participating in investigating and, if necessary,
remediating former MGP 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). In addition, the Company and its subsidiaries 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. A discussion
of these sites by legal entity follows.
CP&L. There are 12 former MGP sites and 14 other sites associated with CP&L
that have required or are anticipated to require investigation and/or
remediation costs. CP&L received insurance proceeds to address costs
associated with environmental liabilities related to its involvement with
MGP sites. All eligible expenses related to these are charged against a
specific fund containing these proceeds. As of December 31, 2002,
approximately $8.0 million remains in this centralized fund with a related
accrual of $8.0 million recorded for the associated expenses of
environmental issues. As CP&L's share of costs for investigating and
remediating these sites become known, the fund is assessed to determine if
additional accruals will be required. CP&L does not believe that it can
provide an estimate of the reasonably possible total remediation costs
beyond what remains in the environmental insurance recovery fund. This is
due to the fact that the sites are at different stages: investigation has
not begun at 15 sites, investigation has begun but remediation cannot be
estimated at seven sites and four sites have begun remediation. CP&L
measures its liability for these sites based on available evidence including
its experience in investigating and remediating environmentally impaired
sites. The process often involves assessing and developing cost-sharing
arrangements with other potentially responsible parties. Once the
environmental insurance recovery fund is depleted, CP&L will accrue costs
for the sites to the extent its liability is probable and the costs can be
reasonably estimated. Presently, CP&L cannot determine the total costs that
may be incurred in connection with the remediation of all sites. According
to current information, these future costs at the CP&L sites are not
expected to be material to the Company's financial condition or results of
operations.
Florida Power. There are two former MGP sites and 11 other active sites
associated with Florida Power that have required or are anticipated to
require investigation and/or remediation costs. As of December 31, 2002 and
2001, Florida Power has accrued approximately $10.9 million and $8.5
million, respectively, for probable and reasonably estimable costs at these
sites. Florida Power does not believe that it can provide an estimate of the
reasonably possible total remediation costs beyond what is currently
accrued. In 2002, Florida Power filed a petition for recovery of
approximately $4.0 million in environmental cost through the Environmental
Cost Recovery Clause with the FPSC. Florida Power was successful with this
filing and will recover costs through rates for investigation and
remediation associated with transmission and distribution substations and
transformers. As more activity occurs at these sites, Florida Power will
assess the need to adjust the accruals. These accruals have been recorded on
an undiscounted basis. Florida Power measures its liability for these sites
based on available evidence including its experience in investigating and
remediating environmentally impaired sites. This process often includes
assessing and developing cost-sharing arrangements with other potentially
responsible parties.
47
NCNG. There are five former MGP sites associated with NCNG that have or are
anticipated to have investigation or remediation costs associated with them.
As of December 31, 2002, NCNG has accrued approximately $2.8 million for
probable and reasonably estimable remediation costs at these sites. These
accruals have been recorded on an undiscounted basis. NCNG measures its
liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often involves assessing and developing cost-sharing
arrangements with other potentially responsible parties. NCNG does not
believe it can provide an estimate of the reasonably possible total
remediation costs beyond the accrual because two of the five sites
associated with NCNG have not begun investigation activities. Therefore,
NCNG cannot currently determine the total costs that may be incurred in
connection with the investigation and/or remediation of all sites. Based
upon current information, the Company does not expect the future costs at
the NCNG sites to be material to the Company's financial condition or
results of operations. On October 16, 2002, the Company announced plans to
sell NCNG to Piedmont Natural Gas Company, Inc. (See Note 3A). The Company
will retain the environmental liability associated with the five former MGP
sites.
Florida Progress Corporation. In 2001, FPC sold its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc. to AEP Resources,
Inc. (See Note 3C). FPC established an accrual to address indemnities and
retained environmental liability associated with the transaction. The
balance in this accrual is $9.9 million at December 31, 2002. FPC estimates
that its maximum contractual liability to AEP Resources, Inc., associated
with Inland Marine Transportation is $60 million. This accrual has been
determined on an undiscounted basis. FPC measures its liability for this
site based on estimable and probable remediation scenarios. The Company
believes that it is reasonably probable that additional costs, which cannot
be currently estimated, may be incurred related to the environmental
indemnification provision beyond the amount accrued. The Company cannot
predict the outcome of this matter.
CP&L, Florida Power, PVI 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 the Company cannot predict the outcome of
these matters, the outcome is not expected to have a material effect on the
consolidated financial position or results of operations.
The Company is also currently in the process of assessing potential costs
and exposures at other environmentally impaired sites. As the assessments
are developed and analyzed, the Company will accrue costs for the sites to
the extent the costs are probable and can be reasonably estimated.
Air and Water Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon
dioxide and mercury. Some of these proposals establish nation-wide caps and
emission rates over an extended period of time. This national
multi-pollutant approach to air pollution control could involve significant
capital 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.
Control equipment that will be installed on North Carolina fossil generating
facilities as part of the North Carolina legislation discussed below may
address some of the issues outlined above. However, the Company cannot
predict the outcome of this matter.
The EPA is 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 initiated civil enforcement actions against other
unaffiliated utilities as part of this initiative. Some of these actions
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 regional transport of
ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in
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order to attain a pre-set state NOx emission levels by May 31, 2004. CP&L is
currently installing controls necessary to comply with the rule. Capital
expenditures needed to meet these measures in North and South Carolina could
reach 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. Designation of areas that do not
attain the standard is proceeding, and further litigation and rulemaking on
this and other aspects of the standard 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 costs of those controls are included in the $370
million cost estimate set forth above. However, further technical analysis
and rulemaking may result in a requirement for additional controls at some
units. The Company cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule as originally promulgated required 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 coal-fired
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 15th 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
April 30, 2002, the EPA published a final rule harmonizing the dates for the
Section 126 Rule and the NOx SIP Call. In addition, the EPA determined in
this rule that the future growth factor estimation methodology was
appropriate. The new compliance date for all affected sources is now May 31,
2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP
Call rule and has indicated it will rescind the Section 126 rule in a future
rule making. The Company expects a favorable outcome of this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. Progress Energy expects its
capital costs to meet these emission targets will be approximately $813
million by 2013. CP&L currently has approximately 5,100 MW of coal-fired
generation capacity in North Carolina that is affected by this legislation.
The legislation requires the emissions reductions to be completed in phases
by 2013, and applies to each utility's total system rather than setting
requirements for individual power plants. The legislation also freezes the
utilities' base rates for five years unless there are extraordinary events
beyond the control of the utilities or unless the utilities persistently
earn a return substantially in excess of the rate of return established and
found reasonable by the NCUC in the utilities' last general rate case.
Further, the legislation allows the utilities to recover from their retail
customers the projected capital costs during the first seven years of the
ten-year compliance period beginning on January 1, 2003. The utilities must
recover at least 70% of their projected capital costs during the five-year
rate freeze period. Pursuant to the new law, CP&L entered into an agreement
with the state of North Carolina to transfer to the state all future
emissions allowances it generates from over-complying with the new federal
emission limits when these units are completed. The new law also requires
the state to undertake a study of mercury and carbon dioxide emissions in
North Carolina. Progress Energy cannot predict the future regulatory
interpretation, implementation or impact of this new law.
Certain historical waste sites exist that are being addressed voluntarily by
Progress Ventures. An immaterial accrual has been established to address
investigation expenses related to these sites. The Company cannot determine
the total costs that may be incurred in connection with these sites.
According to current information, these future costs are not expected to be
material to the Company's financial condition or results of operations.
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Rail Services is voluntarily addressing certain historical waste sites. An
immaterial accrual has been established to address estimable costs. The
Company cannot determine the total costs that may be incurred in connection
with these sites. According to current information, these future costs are
not expected to be material to the Company's financial condition or results
of operations.
Other Environmental Matters
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol,
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush administration
favors voluntary programs. Reductions in carbon dioxide emissions to the
levels specified by the Kyoto Protocol and some legislative proposals could
be materially adverse to Company financials and operations if associated
costs cannot be recovered from customers. The Company favors the voluntary
program approach recommended by the administration, and is evaluating
options for the reduction, avoidance, and sequestration of greenhouse gases.
However, the Company cannot predict the outcome of this matter.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, the EPA determined
in 2000 that regulation of mercury emissions from coal-fired power plants
was appropriate. The EPA is currently developing a Maximum Available Control
Technology (MACT) standard, which is expected to become final in December
2004, with compliance in 2008. Achieving compliance with the MACT standard
could be materially adverse to the Company's financials and operations.
However, the Company cannot predict the outcome of this matter.
2. CP&L, like other electric power companies in North Carolina, pays a
franchise tax levied by the state pursuant to North Carolina General
Statutes ss. 105-116, a state-level annual franchise tax (State Franchise
Tax). Part of the revenue generated by the State Franchise Tax is required
by North Carolina General Statutes ss. 105-116.1(b) to be distributed to
North Carolina cities in which CP&L maintains facilities. CP&L has paid and
continues to pay the State Franchise Tax to the state when such taxes are
due. However, pursuant to an Executive Order issued on February 5, 2002, by
the Governor of North Carolina, the Secretary of Revenue withheld
distributions of State Franchise Tax revenues to cities for two quarters of
fiscal year 2001-2002 in an effort to balance the state's budget.
In response to the state's failure to distribute the State Franchise Tax
proceeds, certain cities in which CP&L maintains facilities adopted
municipal franchise tax ordinances purporting to impose on CP&L a local
franchise tax. The local taxes are intended to be collected for as long as
the state withholds distribution of the State Franchise Tax proceeds from
the cities. The first local tax payments were due August 15, 2002. On August
2, 2002, CP&L filed a lawsuit against the cities seeking to enjoin the
enforcement of the local taxes and to have the local ordinances struck down
because the ordinances are beyond the cities' statutory authority and
violate provisions of the North Carolina and United States Constitutions.
On September 14, 2002, the Governor of North Carolina signed into law a
provision that prevents cities and counties from levying local franchise
taxes on electric utilities. This new legislation makes the lawsuit CP&L
filed in August against certain cities that were seeking to enforce local
franchise tax ordinances moot. As a result of the enactment of this
legislation, the parties have agreed to an Order of Dismissal by Consent,
which has been signed by the judge and filed with the Clerk of Court in
Caswell County.
3. 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.
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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
Federal 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 approval from
the U.S. Nuclear Regulatory Commission 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.
4. 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.
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