Exhibit 99(b)
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
Introduction
Management's Discussion and Analysis should be read with the Consolidated
Financial Statements and has been updated from the 2001 Form 10-K to reflect the
impacts of the implementation of the gross versus net presentation of revenues
under the partial consensus reached in June 2002 on EITF Issue No. 02-03,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities" and the 2002 changes to the business segments. The subsequent events
disclosures have also been updated for matters occurring subsequent to the
filing of the Form 10-K for the year ended December 31, 2001.
Business Segments. Duke Energy Corporation (collectively with its subsidiaries,
Duke Energy), an integrated provider of energy and energy services, offers
physical delivery and management of both electricity and natural gas throughout
the U.S. and abroad. Duke Energy provides these and other services through seven
business segments.
Franchised Electric generates, transmits, distributes and sells electricity in
central and western North Carolina and western South Carolina. It conducts
operations primarily through Duke Power and Nantahala Power and Light. These
electric operations are subject to the rules and regulations of the Federal
Energy Regulatory Commission (FERC), the North Carolina Utilities Commission
(NCUC) and the Public Service Commission of South Carolina (PSCSC).
Natural Gas Transmission provides transportation and storage of natural gas for
customers throughout North America, primarily in the Mid-Atlantic, New England
and southeastern states. It conducts operations primarily through Duke Energy
Gas Transmission Corporation. Interstate natural gas transmission and storage
operations are subject to the FERC's rules and regulations.
Field Services gathers, processes, transports, markets and stores natural gas
and produces, transports, markets and stores natural gas liquids (NGLs). It
conducts operations primarily through Duke Energy Field Services, LLC (DEFS),
which is approximately 30% owned by Phillips Petroleum. Field Services operates
gathering systems in western Canada and 11 contiguous states in the U.S. Those
systems serve major natural gas-producing regions in the Rocky Mountain, Permian
Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, and onshore and
offshore Gulf Coast areas.
Duke Energy North America (DENA) develops, operates and manages merchant
generation facilities and engages in commodity sales and services related to
natural gas and electric power. DENA conducts these operations primarily through
Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC
(DETM). DETM is approximately 40% owned by Exxon Mobil Corporation. DENA
conducts business primarily throughout the U.S. and Canada.
International Energy develops, operates and manages natural gas transportation
and power generation facilities and engages in energy trading and marketing of
natural gas and electric power. It conducts operations primarily through Duke
Energy International, LLC and its activities target the Latin American,
Asia-Pacific and European regions.
Other Energy Services is a combination of businesses that provide engineering,
consulting, construction and integrated energy solutions worldwide, primarily
through Duke Engineering & Services, Inc. (DE&S), Duke/Fluor Daniel (D/FD) and
DukeSolutions, Inc. (DukeSolutions). Other Energy Services also includes Duke
Energy Merchants Holdings, LLC (DEM), which develops new business lines in the
evolving energy commodity markets other than natural gas and power. D/FD is a
50/50 partnership between Duke Energy and Fluor Enterprises, Inc., a wholly
owned subsidiary of Fluor Corporation. (See Note 8 to the Consolidated Financial
Statements.) On January 31, 2002, Duke Energy announced the planned sale of DE&S
to Framatome ANP, Inc. and, on March 13, 2002, Duke Energy announced the planned
sale of DukeSolutions to Ameresco, Inc. (See Current Issues - Subsequent
Events.)
Duke Ventures is composed of other diverse businesses, operating primarily
through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC
(DukeNet) and Duke Capital Partners, LLC (DCP).
2
Crescent develops high-quality commercial, residential and multi-family real
estate projects and manages land holdings primarily in the southeastern U.S.
DukeNet provides fiber optic networks for industrial, commercial and residential
customers. DCP, a wholly owned merchant banking company, provides debt and
equity capital and financial advisory services to the energy industry.
Business Strategy. Duke Energy is one of the world's leading integrated energy
companies. The company's business strategy is to develop integrated energy
businesses in targeted regions where Duke Energy's extensive capabilities in
developing energy assets, operating electricity, natural gas and NGL plants,
optimizing commercial operations and managing risk can provide comprehensive
energy solutions for customers and create superior value for shareholders. The
growth in and restructuring of global energy markets are providing opportunities
for Duke Energy's competitive business segments to capitalize on their extensive
capabilities. Domestically, Duke Energy is investing as opportunities arise in
new merchant power plants throughout the U.S., expanding its natural gas
pipeline infrastructure, advancing its leading position in natural gas gathering
and processing and NGL marketing, and developing its trading and marketing
structured origination expertise across the energy spectrum. Planned expansion
for 2002 includes the acquisition of Westcoast Energy Inc. (Westcoast) for
approximately $8 billion, including the assumption of debt. Westcoast,
headquartered in Vancouver, British Columbia, is a North American energy company
with interests in natural gas gathering, processing, transmission, storage and
distribution, as well as power generation and international energy businesses.
(See Current Issues - Subsequent Events.) Internationally, Duke Energy is
currently focusing on electric and natural gas opportunities in Latin America,
Asia Pacific and Europe.
Franchised Electric continues to increase its customer base, maintain low costs
and deliver high-quality customer service in the Piedmont Carolinas. Franchised
Electric is expected to grow moderately. Expansion will primarily result from
continued growth in the residential and general service sectors, partially
offset by a continuing decline in the textile industry.
Natural Gas Transmission plans to continue its earnings growth rate by executing
a comprehensive strategy of selected acquisitions and expansions, and by
developing expanded services and incremental projects that meet changing
customer needs.
Field Services has developed significant size and scope in natural gas gathering
and processing and NGL marketing. Field Services plans to make additional
investments in gathering, processing and NGL infrastructure. Field Services'
interconnected natural gas processing operations provide an opportunity to
capture fee-based investment opportunities in certain NGL assets, including
pipelines, fractionators and terminals.
DENA plans to continue increasing earnings through acquisitions, divestitures,
construction of greenfield projects and expansion of existing facilities as
regional opportunities are identified, evaluated and realized throughout the
North American marketplace. DENA, through its portfolio management strategy,
seeks opportunities to invest in energy assets in U.S. markets that have
capacity needs and to divest other assets, in whole or in part, when significant
value can be realized. Commodity sales and services related to natural gas and
power continue to expand as DENA provides energy supply, structured origination,
trading and marketing, risk management and commercial optimization services to
large energy customers, energy aggregators and other wholesale companies.
International Energy plans to continue expanding through acquisitions,
divestitures, construction of greenfield projects and expansion of existing
facilities in selected international regions. International Energy's combination
of assets and capabilities and close working relationships with other
subsidiaries of Duke Energy allow it to efficiently deliver natural gas
pipeline, power generation, energy marketing and other services.
Other Energy Services' growth opportunities will be primarily related to D/FD.
Other Energy Services plans to grow by providing an expanding customer base with
a variety of engineering, operating, procurement and construction services in
areas related to energy assets.
3
Duke Ventures plans to expand earnings capabilities in its real estate,
telecommunications and capital financing business units by developing regional
opportunities and by applying extensive experience to new project development.
Duke Energy's business strategy and growth expectations may vary significantly
depending on many factors, including, but not limited to, the pace and direction
of industry restructuring, regulatory constraints, acquisition opportunities,
market volatility and economic trends. However, Duke Energy's growth
expectations do not rely on progress in industry restructuring in North Carolina
and South Carolina.
Results of Operations
In 2001, earnings available for common stockholders were $1,884 million, or
$2.45 per basic share, compared to $1,757 million, or $2.39 per basic share, in
2000. The increase was due primarily to a 6% increase in earnings before
interest and taxes (EBIT), as described below. Current-year EBIT increases on a
comparative basis were partially offset by the prior year's pre-tax gain of $407
million (an after-tax gain of $0.34 per basic share) on the sale of Duke
Energy's 20% interest in BellSouth Carolina PCS, and a current-year, one-time
net-of-tax charge of $96 million (or $0.13 per basic share). This one-time
charge was the cumulative effect of a change in accounting principle for the
January 1, 2001 adoption of Statement of Financial Accounting Standards (SFAS)
No. 133, "Accounting for Derivative Instruments and Hedging Activities." (See
Note 1 to the Consolidated Financial Statements.)
Earnings available for common stockholders increased $270 million in 2000, from
1999 earnings of $1,487 million, or $2.04 per basic share. The increase was due
primarily to a 96% increase in EBIT, as described below, including the BellSouth
Carolina PCS gain. Partially offsetting the increase in EBIT on a comparative
basis was a 1999 after-tax extraordinary gain of $660 million, or $0.91 per
basic share. This gain was from the sale of Panhandle Eastern Pipe Line Company
(PEPL), Trunkline Gas Company (Trunkline) and additional storage related to
those systems, along with Trunkline LNG Company. Higher interest and minority
interest expense in 2000 also partially offset the increase in EBIT.
Earnings per share information provided above has been restated to reflect the
two-for-one common stock split effective January 26, 2001. (See Note 16 to the
Consolidated Financial Statements.)
Operating income for 2001 was $4,100 million, compared to $3,813 million in 2000
and $1,819 million in 1999. EBIT was $4,256 million in 2001, $4,014 million in
2000 and $2,043 million in 1999. Operating income and EBIT are affected by the
same fluctuations for Duke Energy and each of its business segments as described
above. Beginning January 1, 2001, Duke Energy discontinued allocating corporate
governance costs for its business segment analysis. Prior-year business segment
EBIT amounts have been restated to conform to the current-year presentation of
corporate cost allocations. (See Note 3 to the Consolidated Financial Statements
for more information on business segments.) The following table shows the
components of EBIT and a reconciliation from EBIT to net income.
4
- ------------------------------------------------------------------------------------------------
Reconciliation of Operating Income to Net Income (in millions)
- ------------------------------------------------------------------------------------------------
Years Ended December 31,
--------------------------------------------------
2001 2000 1999
--------------------------------------------------
Operating income $4,100 $3,813 $1,819
Other income and expenses 156 201 224
--------------------------------------------------
EBIT 4,256 4,014 2,043
Interest expense 785 911 601
Minority interest expense 327 307 142
--------------------------------------------------
Earnings before income taxes 3,144 2,796 1,300
Income taxes 1,150 1,020 453
--------------------------------------------------
Income before extraordinary item and
cumulative effect of change in
accounting principle 1,994 1,776 847
Extraordinary gain, net of tax - - 660
Cumulative effect of change in accounting
principle, net of tax (96) - -
--------------------------------------------------
Net income $1,898 $1,776 $1,507
- ------------------------------------------------------------------------------------------------
EBIT is the main performance measure used by management to evaluate segment
performance. As an indicator of Duke Energy's operating performance or
liquidity, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with generally
accepted accounting principles. Duke Energy's EBIT may not be comparable to a
similarly titled measure of another company. Business segment EBIT is summarized
in the following table, and detailed discussions follow.
- -----------------------------------------------------------------------------------------------------------
EBIT by Business Segment (in millions)
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
2001 2000 1999
-------------------------------------------
Franchised Electric $1,631 $1,820 $ 942
Natural Gas Transmission 608 562 656
Field Services 336 311 156
Duke Energy North America 1,487 382 219
International Energy 286 341 44
Other Energy Services (149) (7) (86)
Duke Ventures 183 568 165
Other Operations (357) (194) (145)
EBIT attributable to minority interests 231 231 92
-------------------------------------------
Consolidated EBIT $4,256 $4,014 $2,043
- -----------------------------------------------------------------------------------------------------------
Other Operations primarily includes certain unallocated corporate costs. The
amounts discussed below include intercompany transactions that are eliminated in
the Consolidated Financial Statements.
5
Franchised Electric
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
(in millions, except where noted) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 4,746 $ 4,946 $ 4,700
Operating expenses 3,185 3,200 3,880
-------------------------------------------
Operating income 1,561 1,746 820
Other income, net of expenses 70 74 122
-------------------------------------------
EBIT $ 1,631 $ 1,820 $ 942
===========================================
Sales, GWh /a/ 79,685 84,766 81,548
- -----------------------------------------------------------------------------------------------------------
/a/ Gigawatt-hours
Franchised Electric's EBIT decreased $189 million in 2001 as compared to 2000,
due primarily to much milder weather in Franchised Electric's service territory
during the latter part of 2001 and decreased sales to industrial customers,
which were a result of the slowing economy. These decreased sales were slightly
offset by growth in the average number of residential and general service
customers in Franchised Electric's service territory. The 2001 results also
include a $36 million reduction in unbilled revenue receivables, resulting from
a refinement in the estimates used to calculate unbilled kilowatt-hour sales
(see Note 1 to the Consolidated Financial Statements), and $33 million in mutual
insurance distributions that were reclassified from earnings to a deferred
credit account as required by the NCUC, pending final outcome of a regulatory
audit which will likely determine the treatment of those distributions. (See
Current Issues - Regulatory Matters.) The decrease in operating revenues, due to
the decrease in GWh sales, caused an overall decrease in operating expenses, as
variable fuel costs decreased because less fuel was needed. This decrease was
partially offset by increased costs for nuclear and fossil-fueled plant outages
for repairs and maintenance.
In 2000, Franchised Electric's EBIT increased $878 million over 1999, due
primarily to an $800 million expense in 1999 for estimated injuries and damages
claims. (See Note 15 to the Consolidated Financial Statements.) Overall
favorable weather and growth in the average number of customers in Franchised
Electric's service territory resulted in an increase in GWh sales, which also
contributed to the increase in EBIT for 2000. This increase was partially offset
by increased operating costs.
The following table shows the changes in GWh sales and average number of
customers for the past two years.
- -----------------------------------------------------------------------------
Increase (decrease) over prior year 2001 2000
- -----------------------------------------------------------------------------
Residential sales 1.7 % 4.4 %
- -----------------------------------------------------------------------------
General service sales 3.6 % 4.7 %
- -----------------------------------------------------------------------------
Industrial sales (9.6)% (0.5)%
- -----------------------------------------------------------------------------
Total Franchised Electric sales (6.0)% 3.9 %
- -----------------------------------------------------------------------------
Average number of customers 2.0 % 2.5 %
- -----------------------------------------------------------------------------
6
Natural Gas Transmission
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
(in millions, except where noted) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 1,105 $ 1,131 $ 1,230
Operating expenses 504 581 586
-------------------------------------------
Operating income 601 550 644
Other income, net of expenses 7 12 12
-------------------------------------------
EBIT $ 608 $ 562 $ 656
===========================================
Proportional throughput, TBtu /a/ 1,710 1,771 1,893
- -----------------------------------------------------------------------------------------------------------
/a/ Trillion British thermal units
In 2001, EBIT for Natural Gas Transmission increased $46 million compared to
2000, primarily from earnings of East Tennessee Natural Gas Company (ETNG) and
Market Hub Partners (MHP) (acquired in March and September 2000, respectively;
see Note 2 to the Consolidated Financial Statements) and earnings from other
market expansion projects. The decrease in operating revenues for 2001, which
was offset by a decrease in operating expenses, resulted from $112 million in
rate reductions, which became effective in December 2000. These reduced rates
reflect lower recovery requirements for operating costs at Texas Eastern
Transmission, LP, which consists primarily of system fuel and FERC Order 636
transition costs.
Future results of Natural Gas Transmission are expected to be positively
impacted by the Westcoast acquisition. (See Current Issues - Subsequent Events.)
EBIT for Natural Gas Transmission decreased $94 million in 2000 compared to
1999, due primarily to $135 million of EBIT in 1999 that did not recur in 2000.
These earnings in 1999 resulted from $73 million of EBIT from the pipelines sold
to CMS Energy Corporation (CMS) in March 1999; a $24 million gain from the sale
of Duke Energy's interest in the Alliance Pipeline project; and benefits
totaling $38 million from the completion of certain environmental cleanup
programs below estimated costs. These items were partially offset by increased
earnings from market expansion projects, joint ventures such as the Maritimes &
Northeast Pipeline, which was placed into service in December 1999, and earnings
from ETNG and MHP.
7
Field Services
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
(in millions, except where noted) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 8,078 $ 7,404 $ 2,401
Operating expenses 7,581 6,964 2,243
-------------------------------------------
Operating income 497 440 158
Other income, net of expenses 1 6 (2)
Minority interest expense 162 135 -
-------------------------------------------
EBIT $ 336 $ 311 $ 156
===========================================
Natural gas gathered and processed/transported, TBtu/d /a/ 8.6 7.6 5.1
NGL production, MBbl/d /b/ 397.2 358.5 192.4
Natural gas marketed, TBtu/d 1.6 0.7 0.5
Average natural gas price per MMBtu /c/ $ 4.27 $ 3.89 $ 2.27
Average NGL price per gallon /d/ $ 0.45 $ 0.53 $ 0.34
- -----------------------------------------------------------------------------------------------------------
/a/ Trillion British thermal units per day
/b/ Thousand barrels per day
/c/ Million British thermal units
/d/ Does not reflect results of commodity hedges
Field Services' EBIT increased $25 million in 2001 from 2000. Operating revenues
increased due primarily to recognizing a full year of the results of the
combination of Field Services' natural gas gathering, processing and marketing
business with Phillips Petroleum's gas gathering, processing and marketing
unit's midstream natural gas business (the Phillips combination) in March 2000.
(See Note 2 to the Consolidated Financial Statements.) This increase was
partially offset by lower average NGL prices that decreased $0.08 per gallon
from the prior year. (See Quantitative and Qualitative Disclosures About Market
Risk - Commodity Price Risk for information on NGL price sensitivity.) Increased
operating expenses due primarily to the Phillips combination were partially
offset by savings from cost reduction efforts and plant consolidations, and by
the interaction of Field Services' natural gas and NGL purchase contracts with
lower average NGL prices and higher average natural gas prices. The 11% increase
in NGL production, due primarily to the Phillips combination, was offset by
reduced recoveries at facilities, resulting from tightened fractionation spreads
driven by higher average natural gas prices.
In 2000, Field Services' EBIT increased $155 million compared to 1999. The
increase in EBIT and volume activity was primarily due to the Phillips
combination; the acquisition of the natural gas gathering, processing,
fractionation and NGL pipeline business from Union Pacific Resources in April
1999; and other acquisitions and plant expansions. Improved average NGL prices,
which increased 56% over 1999 prices, also contributed significantly to the
increase in EBIT.
8
Duke Energy North America
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
(in millions, except where noted) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 3,297 $ 2,122 $ 830
Operating expenses 1,768 1,667 610
-------------------------------------------
Operating income 1,529 455 220
Other income, net of expenses 2 - 60
Minority interest expense 44 73 61
-------------------------------------------
EBIT $ 1,487 $ 382 $ 219
===========================================
Natural gas marketed, TBtu/d 12.4 11.9 10.5
Electricity marketed and traded, GWh 335,210 275,258 109,634
Proportional megawatt capacity in operation 6,799 5,134 3,532
Proportional megawatt capacity owned /a/ 15,569 8,984 5,799
- -----------------------------------------------------------------------------------------------------------
/a/ Includes under construction or under contract at period end
Compared to 2000, DENA's EBIT increased $1,105 million in 2001. The increase in
EBIT reflects a 32% increase in the proportional megawatt capacity of generation
assets in operation. Increased earnings also resulted from a 4% increase in the
marketing of natural gas volumes and a 22% increase in the marketing and trading
of electricity volumes. Additionally, EBIT increased $63 million over the prior
year due to the sale of DENA's interests in generating facilities, consistent
with its portfolio management strategy, and $110 million due to a charge in 2000
related to receivables for energy sales in California. These increases were
partially offset by increased operating and development costs associated with
business expansion and a current-year charge of $12 million for
non-collateralized accounting exposure to Enron Corporation, which filed for
bankruptcy in 2001. (See Quantitative and Qualitative Disclosures About Market
Risk - Credit Risk.) Changes in the ownership percentage of DENA's
waste-to-energy plants and decreased earnings at DETM resulted in a $29 million
decrease in minority interest expense compared to the prior year.
In 2001, DENA experienced strong growth rates by taking advantage of significant
volatility in the marketplace. While management is taking steps to continue to
increase earnings, 2001 results may not be indicative of DENA's future earnings
trends.
In 2000, EBIT for DENA increased $163 million from 1999, the result of increased
earnings from asset positions, increased trading margins due to price volatility
in natural gas and power, and a $47 million increase in income from the sale of
interests in generating facilities. Operating revenues and expenses increased as
the volumes of natural gas and electricity marketed increased 13% and 151%,
respectively. These increases were partially offset by the $110 million charge
related to receivables for energy sales in California, and increased operating
and development costs associated with business expansion.
9
International Energy
- ------------------------------------------------------------------------------------------------------------
Years Ended December 31,
----------------------------------------
(in millions, except where noted) 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------
Operating revenues $ 830 $ 805 $ 357
Operating expenses 557 483 290
----------------------------------------
Operating income 273 322 67
Other income, net of expenses 36 42 8
Minority interest expense 23 23 31
----------------------------------------
EBIT $ 286 $ 341 $ 44
========================================
Proportional megawatt capacity in operation 4,568 4,226 2,974
Proportional megawatt capacity owned /a/ 5,386 4,876 2,974
Proportional maximum pipeline capacity in operation, MMcf/d /b/ 255 255 83
Proportional maximum pipeline capacity owned /a/, MMcf/d 363 363 255
- ------------------------------------------------------------------------------------------------------------
/a/ Includes under construction or under contract at period end
/b/ Million cubic feet per day
International Energy's EBIT decreased $55 million in 2001 compared to 2000. The
decrease was due primarily to a $54 million gain recognized in 2000 from the
sale of liquefied natural gas ships, and the impact in 2001 of foreign currency
devaluation on the earnings of international operations. However, these were
offset by inflation adjustment clauses in certain contracts and stronger Latin
American operational results.
In 2000, International Energy's EBIT increased $297 million compared to 1999.
The increase was primarily attributable to increased earnings in Latin America,
mainly resulting from new investments. (See Note 2 to the Consolidated Financial
Statements for a discussion of significant acquisitions.) The increase also
included $54 million from the February 2000 sale of liquefied natural gas ships.
Other Energy Services
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
(in millions) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 534 $ 961 $ 989
Operating expenses 688 971 1,075
-------------------------------------------
Operating income (154) (10) (86)
Other income, net of expenses 5 3 -
-------------------------------------------
EBIT $ (149) $ (7) $ (86)
- -----------------------------------------------------------------------------------------------------------
In 2001, EBIT for Other Energy Services decreased $142 million compared to 2000.
Current-year results included approximately $36 million of charges at DE&S and
DukeSolutions for goodwill impairment, approximately $100 million of charges at
Duke Energy Merchants (DEM) related to the Agrifos project and a charge of $24
million for non-collateralized accounting exposure to Enron Corporation, which
filed bankruptcy in 2001. (See Quantitative and Qualitative Disclosures About
Market Risk - Credit Risk.) These charges were partially offset by the prior
year's loss on a D/FD project of $62 million and a $27 million charge at DE&S to
reflect a more conservative revenue recognition approach on its projects. D/FD
uses the percentage-of-completion method to recognize income. (See Note 1 to the
Consolidated Financial Statements for a discussion of revenue recognition.)
Operating revenues and expenses also decreased compared to 2000, due to
cessation of retail commodity trading at DukeSolutions. On January 31, 2002,
Duke Energy announced the planned sale of DE&S to Framatome ANP, Inc. and, on
March 13, 2002, Duke Energy announced the planned sale of DukeSolutions to
Ameresco, Inc. (See Current Issues - Subsequent Events.)
10
EBIT for Other Energy Services improved $79 million in 2000 compared to 1999.
New business activity and decreased operating expenses at DukeSolutions and
earnings related to new projects at D/FD were responsible for improved EBIT in
2000. The results for 2000 also included the D/FD project loss and the DE&S
charge mentioned above. Partially offsetting these amounts were 1999 charges of
$38 million at DE&S and $35 million at DukeSolutions, related to expenses for
severance and office closings associated with repositioning the companies.
Duke Ventures
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
(in millions) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Operating revenues $ 646 $ 797 $ 433
Operating expenses 461 229 268
-------------------------------------------
Operating income 185 568 165
Minority interest expense 2 - -
-------------------------------------------
EBIT $ 183 $ 568 $ 165
- -----------------------------------------------------------------------------------------------------------
EBIT for Duke Ventures decreased $385 million in 2001 compared to 2000, due
mainly to DukeNet's sale of its 20% interest in BellSouth Carolina PCS to
BellSouth Corporation in 2000, for a pre-tax gain of $407 million. This decrease
was minimally offset by increased earnings at Crescent, related primarily to
increased commercial project sales, and the absence of losses related to
DukeNet's BellSouth Carolina PCS investment. Excluding the gain on the sale in
2000, operating revenues and expenses increased due to DCP, which began
operations in late 2000.
In 2000, EBIT for Duke Ventures increased $403 million compared to 1999. This
increase, primarily attributable to the DukeNet gain on the sale mentioned
above, was slightly offset by a decrease in commercial project sales and land
sales at Crescent.
Other Operations
EBIT for Other Operations decreased $163 million in 2001 and $49 million in
2000. The decrease for 2001 was due primarily to increased contributions to the
Duke Energy Foundation (an independent, Internal Revenue Code section 501(c)(3)
entity that funds Duke Energy's charitable contributions), mark-to-market losses
on corporately managed energy risk positions used to hedge exposure to commodity
prices, increased unallocated corporate costs and a prior-year interest refund
from a Revenue Agency Ruling. The decrease in 2000 was due primarily to
increased unallocated corporate costs.
Other Impacts on Earnings Available for Common Stockholders
Interest expense decreased $126 million in 2001, due primarily to lower interest
rates. In 2000, interest expense increased $310 million due to higher average
outstanding debt balances, resulting from acquisitions and expansion.
Minority interest expense increased $20 million in 2001 and $165 million in
2000. Minority interest expense includes expense related to regular
distributions on preferred securities of Duke Energy and its subsidiaries. This
expense increased $39 million in 2001 and $14 million in 2000 related to Catawba
River Associates, LLC (Catawba), which was formed by Duke Energy in September
2000. (See Note 13 to the Consolidated Financial Statements.) In 2000, this
expense increased $21 million due to additional issuances of Duke Energy's trust
preferred securities during 1999. (See Note 12 to the Consolidated Financial
Statements.)
Minority interest expense as shown and discussed in the preceding business
segment EBIT discussions includes only minority interest expense related to EBIT
of Duke Energy's joint ventures. It does not include minority interest expense
related to interest and taxes of the joint ventures. Total minority interest
expense
11
related to the joint ventures (including the portion related to interest and
taxes) decreased $19 million in 2001 and increased $130 million in 2000. The
2001 decrease is due to changes in the ownership percentage of DENA's
waste-to-energy plants and decreased earnings by DETM, DENA's joint venture with
Exxon Mobil Corporation, offset slightly by increased minority interest expense
for Field Services' joint venture with Phillips Petroleum. The 2000 increase was
primarily due to increased minority interest expense at Field Services and DENA,
partially offset by decreased minority interest expense at International Energy
due to its 1999 and 2000 acquisitions. (See Notes 2 and 8 to the Consolidated
Financial Statements for more information on acquisitions and new joint venture
projects.)
Duke Energy's effective tax rate was approximately 37% for 2001, 37% for 2000
and 35% for 1999.
During 2001, Duke Energy recorded a one-time net-of-tax charge of $96 million
related to the cumulative effect of a change in accounting principle for the
January 1, 2001 adoption of SFAS No. 133. This charge related to contracts that
either did not meet the definition of a derivative under previous accounting
guidance or do not qualify as hedge positions under new accounting requirements.
(See Notes 1 and 7 to the Consolidated Financial Statements.)
The sale of PEPL, Trunkline and additional storage related to those systems,
along with Trunkline LNG Company to CMS, closed in March 1999 and resulted in a
$660 million extraordinary gain, after income tax of $404 million. (See Note 1
to the Consolidated Financial Statements.)
Critical Accounting Policies
See Quantitative and Qualitative Disclosures About Market Risk - Risk and
Accounting Policies for a discussion of Mark-to-Market Accounting, Hedge
Accounting and Normal Purchases and Normal Sales, Special Exemption. Also see
Note 1 to the Consolidated Financial Statements for a discussion of significant
accounting policies.
Liquidity and Capital Resources
As of December 31, 2001, Duke Energy had $290 million in Cash and Cash
Equivalents on the Consolidated Balance Sheets. This compares to $622 million as
of December 31, 2000 and $613 million as of December 31, 1999.
Operating Cash Flows
Net cash provided by operations increased $2,370 million in 2001 and decreased
$459 million in 2000. The 2001 increase is due primarily to price movements in
the energy commodities markets which have a direct impact on Duke Energy's use
and generation of cash from operations. Earnings increase as natural gas and
electricity prices move favorably with respect to contracts that Duke Energy
holds. In addition, counterparties may be required to post collateral in cash or
letters of credit if price moves benefit Duke Energy. This mechanism gives Duke
Energy use of those funds on a short-term basis. Conversely, negative price
impacts reduce earnings and may require Duke Energy to post collateral with its
counterparties. Cash collateral posted by Duke Energy is included in Other
Current Assets and cash collateral collected by Duke Energy is included in Other
Current Liabilities on the Consolidated Balance Sheets. In 2000, Duke Energy
posted more collateral with counterparties, reducing cash from operations. In
addition, Duke Energy made tax payments in 2000 related to the sale of pipelines
in 1999. These accounted for the reduced operating cash flows for 2000 compared
to 1999.
12
Investing Cash Flows
Cash used in investing activities increased $1,351 million in 2001 and $1,179
million in 2000. The primary use of cash for investing activities is capital and
investment expenditures, which are detailed by business segment in the following
table.
- -----------------------------------------------------------------------------------------------------------
Capital and Investment Expenditures by Business Segment /a/ (in millions)
- -----------------------------------------------------------------------------------------------------------
Years Ended December 31,
-------------------------------------------
2001 2000 1999
-------------------------------------------
Franchised Electric $ 1,115 $ 661 $ 759
Natural Gas Transmission 748 973 261
Field Services 587 376 1,630
Duke Energy North America 3,213 1,735 1,028
International Energy 442 980 1,779
Other Energy Services 72 230 94
Duke Ventures 773 643 382
Other Operations 90 36 3
-------------------------------------------
Total consolidated $ 7,040 $ 5,634 $ 5,936
- -----------------------------------------------------------------------------------------------------------
/a/ Amounts are gross of cash received from acquisitions
Capital and investment expenditures increased $1,406 million in 2001 compared to
2000. The increase reflects additional expansion and development expenditures
(especially related to DENA's generating facilities), refurbishment and upgrades
to existing assets (primarily related to Franchised Electric) and minor
acquisitions of businesses and assets. Also in 2001, Natural Gas Transmission
invested in a 50% interest in Gulfstream Natural Gas System, LLC, a joint
interstate natural gas pipeline development that will extend from Mississippi
and Alabama across the Gulf of Mexico to Florida. These increases were partially
offset by Natural Gas Transmission's acquisition of ETNG for approximately $390
million and of MHP for approximately $250 million in cash, and International
Energy's approximately $280 million tender offer for Companhia de Geracao de
Energia Eletrica Paranapanema (Paranapanema) in 2000. (See Note 2 to the
Consolidated Financial Statements for more information about significant
acquisitions.)
Capital and investment expenditures decreased by $302 million in 2000 compared
to 1999. In 2000, Natural Gas Transmission's capital expenditures increased
primarily for business expansion related to the acquisitions of ETNG and MHP.
Also in 2000, DENA began construction of a number of power generation plants in
the U.S. and continued capital expenditures on ongoing projects. International
Energy's business expansion included completion of the Paranapanema tender offer
and the approximately $405 million acquisition of Dominion Resources, Inc.'s
portfolio of hydroelectric, natural gas and diesel power generation businesses
in Latin America.
Offsetting the capital and investing expenditures were cash proceeds of $400
million from the sale of Duke Energy's 20% interest in BellSouth Carolina PCS in
2000 and $1,900 million from the sale of pipelines to CMS in 1999. (See Note 1
to the Consolidated Financial Statements for more information on the sale of the
pipelines.)
Projected 2002 capital and investment expenditures for Duke Energy are
approximately $8.0 billion, of which over 80% is planned for competitive
business segments not subject to state rate regulation. This projection includes
approximately $6.5 billion for acquisitions and other expansion opportunities
and $1.5 billion for existing plant upgrades. The above amounts do not include
expenditures for the Westcoast acquisition. (See Current Issues - Subsequent
Events.)
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,
acquisition opportunities, market volatility and economic trends.
13
Duke Energy's growth initiatives, along with dividends, debt repayments and
operating requirements are expected to be funded by cash from operations, debt
and capital market financings, project financings, common stock issuances
through its InvestorDirect Choice Plan and employee benefit plans, and proceeds
from the sale of assets. These financing opportunities are dependent upon the
opportunities presented and favorable market conditions. Additionally, internal
cash generation should fund approximately half of the capital needs. Management
believes Duke Energy has adequate financial resources to meet its future needs.
Financing Cash Flows
Duke Energy's consolidated capital structure at December 31, 2001, including
short-term debt, was 46% debt, 41% common equity, 7% minority interests, 5%
trust preferred securities and 1% preferred stock. Fixed charges coverage,
calculated using Securities and Exchange Commission (SEC) guidelines, was 3.8
times for 2001, 3.6 times for 2000 and 2.7 times for 1999.
During 2001, DEFS issued $250 million of 6.875% senior unsecured notes due in
2011 and $300 million of 5.75% senior unsecured notes due in 2006. The proceeds
were used to repay DEFS' short-term debt. Also during 2001, Duke Capital
Corporation (a wholly owned subsidiary of Duke Energy), increased its note
payable to D/FD by $427 million, to $568 million as of December 31, 2001. The
weighted-average interest rate on this note for 2001 was 4.05%. (See Notes 8 and
10 to the Consolidated Financial Statements.)
In March 2001, Duke Energy completed an offering of 25 million shares of common
stock, priced at $38.98 per share, before underwriting discount and other
offering expenses. In addition, Duke Energy completed an offering of
approximately 31 million mandatory convertible securities (Equity Units), at $25
per unit, before underwriting discount and other offering expenses. The Equity
Units consist of senior notes of Duke Capital Corporation (which are included in
Long-term Debt on the Consolidated Balance Sheets; see Note 10 to the
Consolidated Financial Statements), and purchase contracts obligating the
investors to purchase shares of Duke Energy's common stock in 2004. The number
of shares to be issued in 2004 will be based on the price of the common stock at
conversion. Also in March 2001, the underwriters exercised options granted to
them to purchase an additional 3.75 million shares of common stock and four
million Equity Units at the original issue prices, less underwriting discounts,
to cover over-allotments made during the offerings. Total net proceeds from the
offerings, approximately $1.9 billion, were used to repay short-term debt and
for other corporate purposes.
In November 2001, Duke Energy completed an offering of 30 million Equity Units,
at $25 per unit, before underwriting discount and other offering expenses. The
Equity Units consist of senior notes of Duke Capital Corporation (which are
included in Long-term Debt on the Consolidated Balance Sheets; see Note 10 to
the Consolidated Financial Statements), and purchase contracts obligating the
investors to purchase shares of Duke Energy's common stock in 2004. The number
of shares to be issued in 2004 will be based on the price of the common stock at
conversion. The net proceeds from the offering of approximately $731 million
provided a component of the permanent financing for the Westcoast acquisition.
Prior to the close of the Westcoast acquisition, the net proceeds of the
offering were used to manage working capital needs.
During 2001, Duke Energy redeemed eight issues of its first and refunding
mortgage bonds to take advantage of the general decline in interest rates. The
total face value of the redeemed bonds was $511 million, with interest rates
ranging from 5.875% to 8.3%. To fund these redemptions, Duke Energy issued
commercial paper and used cash proceeds generated from short-term investments.
In January 2002, Duke Energy issued $750 million of 6.25% senior unsecured bonds
due in 2012 and $250 million of floating rate (based on the three-month London
Interbank Offered Rate (LIBOR) plus 0.35%) senior unsecured bonds due in 2005.
The proceeds from these issuances were used to manage working capital needs.
In February 2002, Duke Capital Corporation issued $500 million of 6.25% senior
unsecured bonds due in 2013 and $250 million of 6.75% senior unsecured bonds due
in 2032. In addition, Duke Capital
14
Corporation, through a private placement transaction, issued $500 million of
floating rate (based on the one-month LIBOR plus 0.65%) senior unsecured bonds
due in 2003. The proceeds from these issuances were used to manage working
capital needs and to fund a portion of the cash consideration for the Westcoast
acquisition.
Under its commercial paper, medium-term notes and extendible commercial notes
(ECNs) programs, Duke Energy had the ability to borrow up to $5,358 million at
December 31, 2001 compared with $5,720 million at December 31, 2000. These
programs do not have termination dates. The following table summarizes the
commercial paper, medium-term notes and ECNs as of December 31, 2001.
- ------------------------------------------------------------------------------------------------------------
Duke Energy Duke
Duke Capital Field Energy
(in millions) Duke Energy Corporation /a/ Services International Total
- ------------------------------------------------------------------------------------------------------------
Commercial paper $1,250 $1,550 $675 $383 /b/ $3,858
ECNs 500 1,000 - - 1,500
------------------------------------------------------------------------------------
Total $1,750 $2,550 $675 $383 $5,358
- ------------------------------------------------------------------------------------------------------------
/a/ Duke Capital Corporation provides financing and credit enhancement services
for its subsidiaries.
/b/ Includes ability to issue medium-term notes
The total amount of Duke Energy's bank credit facilities was approximately
$4,606 million as of December 31, 2001 compared with $4,205 million as of
December 31, 2000. Some of the credit facilities support the issuance of
commercial paper; therefore, the issuance of commercial paper reduces the amount
available under these credit facilities. As of December 31, 2001, approximately
$2,970 million was outstanding in the form of commercial paper, medium-term
notes and ECNs, and approximately $38 million of borrowings were outstanding
under the bank credit facilities. The credit facilities expire from 2002 to 2004
and are not subject to minimum cash requirements; however, borrowings and
issuances of letters of credit under approximately $1,100 million of these
facilities are subject to and dependent on the senior unsecured debt ratings of
Duke Capital Corporation (currently rated A3/A/A). Ratings of Baa2, BBB or the
equivalent by at least two of Moody's Investors Service, Standard & Poor's and
Fitch, Inc. must be maintained to obtain additional borrowings and issuances of
letters of credit. Any outstanding borrowings would not become due and payable.
(See Note 10 to the Consolidated Financial Statements for more information on
the bank credit facilities.)
As of December 31, 2001, Duke Energy and its subsidiaries had effective SEC
shelf registrations for up to $3,500 million in gross proceeds from debt and
other securities. Subsequent to December 31, 2001, these SEC shelf registrations
have been reduced by $1,750 million for the senior and unsecured bonds issued in
January and February 2002, excluding the private placement transaction. Under
the SEC shelf registrations, such securities may be issued as senior notes,
first and refunding mortgage bonds, subordinated notes, trust preferred
securities, Duke Energy common stock, stock purchase contracts or stock purchase
units.
In 2000, Duke Energy issued $250 million 7.125% senior unsecured bonds due in
2012 with a put option that gives investors the choice to put the bond to Duke
Energy at par value in September 2002 or extend the maturity until 2012. If
extended, the bonds would be recouponed at 5.7% plus the Duke Energy 10-year
credit spread on the extension date. Also in 2000, Duke Capital Corporation
issued $150 million senior unsecured bonds due in 2003 that become due and
payable if Duke Capital Corporation's debt ratings fall below BBB.
In 2000, Catawba, a fully consolidated financing entity managed by a subsidiary
of Duke Energy, issued $1,025 million of preferred member interests to a
third-party investor. Catawba subsequently advanced the proceeds from the sale
to DE Power Generation, LLC, a wholly owned subsidiary of Duke Energy, which
indirectly owns or leases six merchant power generation facilities located in
California, Maine and Indiana. Catawba is a limited liability company with a
separate existence and identity from its preferred members, and the assets of
Catawba are separate and legally distinct from Duke Energy. The preferred member
interests receive quarterly a preferred return equal to an adjusted floating
reference rate (approximately
15
5.20% for the full year ended December 31, 2001). (See Note 13 to the
Consolidated Financial Statements for more information.)
To maintain financial flexibility and reduce the amount of financing needed for
growth opportunities, Duke Energy's Board of Directors adopted a dividend policy
in 2000 that maintains dividends at the current quarterly rate of $0.275 per
share, subject to declaration by the Board of Directors. This policy is
consistent with Duke Energy's growth profile and strikes a balance between
providing a competitive dividend yield and ensuring that cash is available to
fund Duke Energy's growth. Duke Energy has paid quarterly cash dividends for 75
consecutive years. Dividends on common and preferred stocks in 2002 are expected
to be paid on March 15, June 17, September 16 and December 16, subject to the
discretion of the Board of Directors.
Duke Energy's InvestorDirect Choice Plan, a stock purchase and dividend
reinvestment plan, allows investors to reinvest dividends in new issuances of
common stock and to purchase common stock directly from Duke Energy. Issuances
under this plan were not material in 2001, 2000 or 1999.
Duke Energy used authorized but unissued shares of its common stock to meet 2001
and 2000 employee benefit plan contribution requirements. This practice is
expected to continue in 2002.
Contractual Obligations and Commercial Commitments
As part of its normal business, Duke Energy is a party to various financial
guarantees, performance guarantees and other contractual commitments to extend
guarantees of credit and other assistance to various subsidiaries, investees and
other third parties. These arrangements are largely entered into by Duke Capital
Corporation. To varying degrees, these guarantees involve elements of
performance and credit risk, which are not included on the Consolidated Balance
Sheets. The possibility of Duke Energy having to honor its contingencies is
largely dependent upon future operations of various subsidiaries, investees and
other third parties, or the occurrence of certain future events. Duke Energy
would record a reserve if events occurred that required that one be established.
(See Note 15 to the Consolidated Financial Statements for more information on
financial guarantees.)
In addition, Duke Energy enters into various fixed-price, non-cancelable
commitments to purchase or sell power (tolling arrangements or power purchase
contracts), take-or-pay arrangements, transportation or throughput agreements
and other contracts that may or may not be recognized on the Consolidated
Balance Sheets. Some of these arrangements may be recognized at market value on
the Consolidated Balance Sheets as trading contracts or qualifying hedge
positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging
Transactions.
16
The following table summarizes Duke Energy's contractual cash obligations for
each of the years presented.
- ----------------------------------------------------------------------------------------------------------------------
Contractual Cash Obligations (in millions)
- ----------------------------------------------------------------------------------------------------------------------
Payments Due
--------------------------------------------------------------------------
2002 2003 2004 2005 2006 Thereafter
- ----------------------------------------------------------------------------------------------------------------------
Long-term debt (Note 10) $ 261 $ 576 $ 883 $1,016 $2,101 $7,745
Preferred securities (Notes 12 and 14) 13 2 2 2 2 1,424
Operating leases (Note 15) 87 70 57 43 34 75
Firm capacity payments /a/ 231 177 142 123 109 563
Purchase commitments /b/ 629 262 527 586 268 -
Other /c/ 1,635 211 - - - -
------------------------------------------------------------------------
Total contractual cash obligations $2,856 $1,298 $1,611 $1,770 $2,514 $9,807
- ----------------------------------------------------------------------------------------------------------------------
/a/ Includes firm capacity payments that provide Duke Energy with uninterrupted
firm access to natural gas transportation and storage, electricity
transmission capacity, and the option to convert natural gas to electricity
at third-party owned facilities (tolling arrangements) in some natural gas
and power locations throughout North America. Based on current estimates,
the market value of underlying transportation, storage and electricity
available under such arrangements exceeds the discounted fair value of the
capacity payments.
/b/ Amounts include Duke Energy's obligations as of December 31, 2001 to
purchase gas-fired turbines, steam turbines and heat recovery steam
generators (HRSG). Commitments under the turbine and HRSG purchase
agreements are payable consistent with the delivery schedule. The purchase
agreements include milestone requirements by the manufacturer and provide
Duke Energy with the ability to cancel each discrete purchase order
commitment in exchange for a termination fee, which escalates over time.
The amounts included above assume that all turbines and HRSGs will be
purchased. However, if Duke Energy had terminated the turbine and HRSG
purchase orders at December 31, 2001 as allowed by the agreements, the
termination fee would have been $569 million. Approximately 50% of this
termination fee relates to turbines that Duke Energy has allocated to power
generation facilities currently under construction.
/c/ Amounts include engineering, procurement and construction costs for power
generation facilities in North America. Such amounts are payable to D/FD, a
related party in which Duke Energy has a 50% equity interest, and excluded
from the Consolidated Balance Sheets since Duke Energy accounts for D/FD
using the equity method of accounting.
Duke Energy also has substantial commitments as part of it growth strategy and
ongoing construction programs. (See Investing Cash Flows for 2002's projected
expenditures.)
The following table summarizes the commercial commitments in effect as of
December 31, 2001 by expiration date.
- --------------------------------------------------------------------------------------------------------------------
Commercial Commitments (in millions)
- --------------------------------------------------------------------------------------------------------------------
Total
Amounts Amount of Commitment Expiring Each Period
-------------------------------------------------------------------------
(see Note 15) Committed 2002 2003 2004 2005 2006 Thereafter
- --------------------------------------------------------------------------------------------------------------------
Guaranteed debt of affiliates $200 $ - $ - $ - $ - $ - $200
- --------------------------------------------------------------------------------------------------------------------
Surety and bid bonds /a/ 198 165 32 1 - - -
- --------------------------------------------------------------------------------------------------------------------
Letters of credit 181 151 10 - 20 - -
- --------------------------------------------------------------------------------------------------------------------
/a/ Surety bonds are contractual agreements where Duke Energy obligates itself
to a second party to answer for the default of a third party, such as a
contractor. Bid bonds are issued to the owners of projects and are subject
to full or partial forfeiture for failure to perform obligations arising
from a successful bid. All public and some private jobs require a bid bond
or cashiers check to be submitted with a bid.
17
Quantitative and Qualitative Disclosures About Market Risk
Risk and Accounting Policies
Duke Energy is exposed to market risks associated with commodity prices, credit
exposure, interest rates, equity prices and foreign currency exchange rates.
Management has established comprehensive risk management policies to monitor and
manage these market risks. Duke Energy's Policy Committee is responsible for the
overall approval of market risk management policies and the delegation of
approval and authorization levels. The Policy Committee is composed of senior
executives who receive periodic updates from the Chief Risk Officer (CRO) on
market risk positions, corporate exposures, credit exposures and overall risk
management activities. The CRO is responsible for the overall management of
credit risk and commodity price risk, including monitoring exposure limits.
Mark-to-Market Accounting (MTM accounting). Under the MTM accounting method, an
asset or liability is recognized at fair value and the change in the fair value
of that asset or liability is recognized in earnings during the current period.
This accounting method has been used by other industries for many years, and in
1998 the Financial Accounting Standards Board's (FASB) Emerging Issues Task
Force (EITF) issued guidance that required MTM accounting for energy trading
contracts. MTM accounting reports contracts at their "fair value," (the value a
willing third party would pay for the particular contract at the time a
valuation is made).
When available, quoted market prices are used to record a contract's fair value.
However, market values for energy trading contracts may not be readily
determinable because the duration of the contracts exceeds the liquid activity
in a particular market. If no active trading market exists for a commodity or
for a contract's duration, holders of these contracts must calculate fair value
using pricing models or matrix pricing based on contracts with similar terms and
risks. This is validated by an internal group independent of Duke Energy's
trading area. Holders of thinly traded securities or investments (mutual funds,
for example) use similar techniques to price such holdings. Correlation and
volatility are two significant factors used in the computation of fair values.
Duke Energy validates its internally developed fair values by comparing
locations/durations that are highly correlated, using forecasted market
intelligence and mathematical extrapolation techniques. While Duke Energy uses
industry best practices to develop its pricing models, changes in Duke Energy's
pricing methodologies or the underlying assumptions could result in
significantly different fair values, income recognition and realization in
future periods.
Hedge Accounting. Hedging typically refers to the mechanism that Duke Energy
uses to mitigate the impact of volatility associated with price fluctuations.
Hedge accounting treatment is used when Duke Energy contracts to buy or sell a
commodity such as natural gas or electricity at a fixed price for future
delivery corresponding with anticipated physical sales or purchases of natural
gas and power (cash flow hedge). In addition, hedge accounting treatment is used
when Duke Energy holds firm commitments or asset positions, and enters into
transactions that "hedge" the risk that the price of natural gas or power may
change between the contract's inception and the physical delivery date of the
commodity (fair value hedge). While the majority of Duke Energy's hedging
transactions are used to protect the value of future cash flows related to its
physical assets, to the extent the hedge is effective, Duke Energy recognizes in
earnings the value of the contract when the commodity is purchased or sold, or
the hedged transaction occurs or settles.
Normal Purchases and Normal Sales, Special Exemption. A unique characteristic of
the electric power industry is that electricity cannot be readily stored in
significant quantities. As a result, some of the contracts to buy and sell
electricity allow the buyer some flexibility in determining when to take
electricity and in what quantity to match fluctuating demand. These contracts
would normally meet the definition of a derivative requiring MTM or hedge
accounting. However, because electricity cannot be readily stored in significant
quantities and an entity engaged in selling electricity is obligated to maintain
sufficient capacity
18
to meet the electricity needs of its customer base, an option contract for the
purchase of electricity qualifies for the normal purchases and sales exemption
described in Paragraph 10 of SFAS No. 133 and Derivative Implementation Group
(DIG) Issue No. C15, "Scope Exceptions: Normal Purchases and Normal Sales
Exception for Option-Type Contracts and Forward Contracts in Electricity."
Therefore, contracts that Duke Energy holds for the sale of power in future
periods that meet the criteria in DIG Issue No. C15 have been designated as
"normal purchase, normal sales" contracts, and are exempted from recognition in
the Consolidated Financial Statements until power is delivered. Duke Energy
tracks these contracts separately in its hedge portfolio, but no value for these
contracts is included in the Consolidated Financial Statements until power is
actually delivered.
Duke Energy's wholesale energy portfolio in North America includes the merchant
generation facilities and trading contracts held for power, natural gas, crude
oil and petroleum products. Of the total estimated value of this portfolio,
approximately 80% is attributed to the anticipated value of merchant generation
facility capacity owned or controlled by Duke Energy. This portion of the value
of the merchant generation portfolio is anticipated to be realized in future
periods as the generation facilities are dispatched. A portion of this future
value is secured by hedge contracts. Of the unhedged capacity, dispatch
performance, and in some cases price, has been further secured through contracts
designated as normal purchases and normal sales. Only the contracts designated
and effective as qualifying hedges are reflected on Duke Energy's Consolidated
Balance Sheets at fair value. Changes in the fair value of hedging contracts do
not affect current-period earnings. Normal purchase and normal sales contracts
are not subject to accounting recognition until contract performance occurs. The
remaining percentage of the total estimated value of the merchant generation
portfolio is attributed to the current value of trading contracts. These
contracts are subject to MTM accounting and changes in the contract fair value
are recorded as part of current-period earnings. The table below represents the
value by year of Duke Energy's North American merchant generation portfolio. It
does not include the value of trading positions, or hedges of other commodity
risks or exposures.
------------------------------------------------------------------------------------------------------
North American Merchant Generation Portfolio Value as of December 31, 2001 (in millions)
------------------------------------------------------------------------------------------------------
Maturity in 2005 Total
Maturity in 2002 Maturity in 2003 Maturity in 2004 and Thereafter /a/ Portfolio Value
------------------------------------------------------------------------------------------------------
$814 $819 $835 $3,930 $6,398
------------------------------------------------------------------------------------------------------
/a/ For purposes of calculating total portfolio value, model valuations were
calculated through 2010.
As of December 31, 2001, the portion hedged of DENA's expected output of its
merchant generation portfolio was 91%, 62% and 62% for 2002, 2003 and 2004,
respectively, through derivative contracts such as forward natural gas purchases
and forward power sales.
Commodity Price Risk
Duke Energy, substantially through its subsidiaries, is exposed to the impact of
market fluctuations in the price of natural gas, electricity and other
energy-related products marketed and purchased. Duke Energy employs established
policies and procedures to manage its risks associated with these market
fluctuations using various commodity derivatives, including forward contracts,
futures, swaps and options for trading purposes and for activity other than
trading activity (primarily hedge strategies). (See Notes 1 and 7 to the
Consolidated Financial Statements.)
Trading. The risk in the trading portfolio is measured and monitored on a daily
basis utilizing a Value-at-Risk model to determine the potential one-day
favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is
monitored daily in comparison to established thresholds. Other measures are also
used to limit and monitor risk in the trading portfolio (which includes all
trading contracts not designated as hedge positions) on monthly and annual
bases. These measures include limits on the nominal size of positions and
periodic loss limits.
19
DER computations are based on historical simulation, which uses price movements
over a specified period (generally ranging from seven to 14 days) to simulate
forward price curves in the energy markets to estimate the potential favorable
or unfavorable impact of one day's price movement on the existing portfolio. The
historical simulation emphasizes the most recent market activity, which is
considered the most relevant predictor of immediate future market movements for
natural gas, electricity and other energy-related products. DER computations
utilize several key assumptions, including a 95% confidence level for the
resultant price movement and the holding period specified for the calculation.
Duke Energy's DER amounts for instruments held for trading purposes are shown in
the following table.
- ---------------------------------------------------------------------------------------------------------------------
Daily Earnings at Risk (in millions)
- ---------------------------------------------------------------------------------------------------------------------
Estimated Average Estimated Average High One-Day Impact Low One-Day Impact
One-Day Impact on One-Day Impact on on EBIT for on EBIT for
EBIT for 2001 /a/ EBIT for 2000 2001 /a/ 2001
- ---------------------------------------------------------------------------------------------------------------------
Calculated DER $21 $18 $86 $7
- ---------------------------------------------------------------------------------------------------------------------
/a/ Amounts include the impact of one origination contract that was initiated
and hedged during the current year. Duke Energy's Risk Management Committee
approved increased DER limits for this specific contract. Excluding this
contract, average and one-day high 2001 DER amounts would have been $16
million and $43 million, respectively.
DER is an estimate based on historical price volatility. Actual volatility can
exceed assumed results. DER also assumes a normal distribution of price changes;
thus, if the actual distribution is not normal, the DER may understate or
overstate actual results. DER is used to estimate the risk of the entire
portfolio, and for locations that do not have daily trading activity, it may not
accurately estimate risk due to limited price information. Stress tests are
employed in addition to DER to measure risk where market data information is
limited. In the current DER methodology, options are modeled in a manner
equivalent to forward contracts which may understate the risk.
Duke Energy's exposure to commodity price risk is influenced by a number of
factors, including contract size, length, market liquidity, location and unique
or specific contract terms. The following table illustrates the movements in the
fair value of Duke Energy's trading instruments during 2001.
- -------------------------------------------------------------------------------------------------------
Changes in Fair Value of Trading Contracts (in millions)
- -------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at the beginning of the year $ 605
Contracts realized or otherwise settled during the year (746)
Fair value of contracts entered into during the year 622
Changes in fair value amounts attributable to changes in valuation techniques (6)
Other changes in fair values 749
----------------------
Fair value of contracts before SFAS No. 133 transition adjustment 1,224
SFAS No. 133 transition adjustment (155)
----------------------
Fair value of contracts outstanding at the end of the year $ 1,069
- -------------------------------------------------------------------------------------------------------
For the year ended December 31, 2001, the unrealized net margin recognized in
operating income was $619 million as compared to $139 million for 2000 and $41
million for 1999. The fair value of these contracts is expected to be realized
in future periods, as detailed in the following table. The amount of cash
ultimately realized for these contracts will differ from the amounts shown in
the following table due to factors such as market volatility, counterparty
default and other unforeseen events that could impact the amount and/or
realization of these values. At December 31, 2001, Duke Energy held cash or
letters of credit of $1,071 million to secure such future performance, and had
deposited with counterparties $178 million of such collateral to secure its
obligations to provide such future services. Collateral amounts held or posted
vary depending on the value of the underlying contracts and cover trading,
normal purchases and normal sales, and hedging contracts outstanding. Duke
Energy may be required to return held collateral and post additional collateral
should price movements adversely impact the value of open contracts or
positions.
20
When available, Duke Energy uses observable market prices for valuing its
trading instruments. When quoted market prices are not available, management
uses established guidelines for the valuation of these contracts. Management may
use a variety of reasonable methods to assist in determining the valuation of a
trading instrument, including analogy to reliable quotations of similar trading
instruments, pricing models, matrix pricing and other formula-based pricing
methods. These methodologies incorporate factors for which published market data
may be available. All valuation methods employed by Duke Energy are approved by
an independent internal corporate risk management organization.
The following table shows the fair value of Duke Energy's trading portfolio as
of December 31, 2001.
- -------------------------------------------------------------------------------------------------------------
Fair Value of Trading Contracts
as of December 31, 2001 (in millions)
-------------------------------------------------------------------------
Maturity in
Maturity in Maturity in Maturity in 2005 and Total Fair
Sources of Fair Value 2002 2003 2004 Thereafter Value
- -------------------------------------------------------------------------------------------------------------
Prices supported by quoted market
prices and other external sources $ 457 $153 $ 9 $ 26 $ 645
Prices based on models and other
Valuation methods (104) 11 128 389 424
- -------------------------------------------------------------------------------------------------------------
Total $ 353 $164 $137 $415 $1,069
- -------------------------------------------------------------------------------------------------------------
The "prices supported by quoted market prices and other external sources"
category includes Duke Energy's New York Mercantile Exchange (NYMEX) futures
positions in natural gas and crude oil. The NYMEX has currently quoted prices
for the next 32 months. In addition, this category includes Duke Energy's
forward positions and options in natural gas and power and natural gas basis
swaps at points for which over-the-counter (OTC) broker quotes are available. On
average, OTC quotes for natural gas and power forwards and swaps extend 22 and
32 months into the future, respectively. OTC quotes for natural gas and power
options extend 12 months into the future, on average. Duke Energy values these
positions against internally developed forward market price curves that are
constantly validated and recalibrated against OTC broker quotes. This category
also includes "strip" transactions whose prices are obtained from external
sources and then modeled to daily or monthly prices as appropriate.
The "prices based on models and other valuation methods" category includes (i)
the value of options not quoted by an exchange or OTC broker, (ii) the value of
transactions for which an internally developed price curve was constructed as a
result of the long dated nature of the transaction or the illiquidity of the
market point, and (iii) the value of structured transactions. It is important to
understand that in certain instances structured transactions can be decomposed
and modeled by Duke Energy as simple forwards and options based on prices
actively quoted. Although the valuation of the simple structures might not be
different from the valuation of contracts in other categories, the effective
model price for any given period is a combination of prices from two or more
different instruments and therefore have been included in this category due to
the complex nature of these transactions.
The value of Duke Energy's trading portfolio valuation adjustments for
liquidity, credit and cost of service is reflected in the above amounts.
Hedging Strategies. Some Duke Energy subsidiaries are exposed to market
fluctuations in the prices of energy commodities related to their power
generating and natural gas gathering, processing and marketing activities. Duke
Energy closely monitors the risks associated with these commodity price changes
on its future operations and, where appropriate, uses various commodity
instruments such as electricity, natural gas, crude oil and NGL contracts to
hedge the value of its assets and operations from such price risks. In
accordance with SFAS No. 133, Duke Energy's primary use of energy commodity
derivatives is to hedge the output and production of assets it physically owns.
Contract terms are up to 13 years; however, since these contracts are designated
and qualify as effective hedge positions of future cash flows, or fair values of
21
assets owned by Duke Energy, to the extent that the hedge relationships are
effective, their market value change impacts are not recognized in current
earnings. The unrealized gains or losses on these contracts are deferred in
Other Comprehensive Income (OCI) or included in Other Current or Noncurrent
Assets or Liabilities on the Consolidated Balance Sheets, in accordance with
SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with
the transaction being hedged. (See Notes 1 and 7 to the Consolidated Financial
Statements.) However, in instances where the hedging contract no longer
qualifies for hedge accounting, amounts included in OCI through the date of
de-designation remain in OCI until the underlying transaction actually occurs.
The derivative contract (if continued as an open position) will be marked to
market currently through earnings. Several factors influence the effectiveness
of a hedge contract, including counterparty credit risk.
The following table shows when gains and losses deferred on the Consolidated
Balance Sheets for derivative instruments qualifying as effective hedges of firm
commitments or anticipated future transactions will be recognized into earnings.
Contracts with terms extending several years are generally valued using models
and assumptions developed internally or by industry standards. However, as
mentioned previously, the gains and losses for these contracts are not
recognized in earnings until settlement at their then market price. Therefore,
assumptions and valuation techniques for these contracts have no impact on
reported earnings prior to settlement.
The fair value of Duke Energy's qualifying hedge positions at a point in time is
not necessarily indicative of the value realized when such contracts settle.
------------------------------------------------------------------------------------------------------
Fair Value of Hedge Position Contracts as of December 31, 2001 (in millions)
------------------------------------------------------------------------------------------------------
Maturity in 2005 Total
Maturity in 2002 Maturity in 2003 Maturity in 2004 and Thereafter Contract Value
------------------------------------------------------------------------------------------------------
$454 $156 $71 $(38) $643
------------------------------------------------------------------------------------------------------
In addition to the hedge contracts described above and recorded on the
Consolidated Balance Sheets, Duke Energy enters into other contracts that
qualify for the normal purchases and sales exemption described in Paragraph 10
of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward
agreements to sell power, bear the same counterparty credit risk as the hedge
contracts described above. Under the same risk reduction guidelines used for
other contracts, normal purchases and sales contracts are also subject to
collateral requirements. Income recognition and realization related to these
contracts coincide with the physical delivery of power.
Based on a sensitivity analysis as of December 31, 2001, it was estimated that a
difference of one cent per gallon in the average price of NGLs in 2002 would
have a corresponding effect on EBIT of approximately $6 million, after
considering the effect of Duke Energy's commodity hedge positions.
Comparatively, the same sensitivity analysis as of December 31, 2000 estimated
that EBIT would have changed by approximately $8 million in 2001. Based on the
sensitivity analyses associated with other commodities' price changes, net of
Duke Energy's commodity hedge positions, the effect on EBIT was not material as
of December 31, 2001 or 2000. Duke Energy's qualifying hedge positions protect
it from immediate earnings impact for adverse price movements. The resulting
gains and losses are deferred on the Consolidated Balance Sheets until cash
settlement occurs, provided that the hedge positions remain effective.
These hypothetical adverse impacts do not consider the likely positive impact
that price movements would have on Duke Energy's physical purchases and sales of
natural gas and electricity which these contracts hedge. The hedge contracts are
intended to mitigate the impact that price changes have on Duke Energy's
physical positions. Therefore, although the fair value of these positions may
decline with adverse price changes, the impact on results would be minimal as
Duke Energy's physical positions are inversely affected by such changes.
22
Credit Risk
Duke Energy's principal customers for power and natural gas marketing services
are industrial end-users and utilities located throughout the U.S., Canada, Asia
Pacific, Europe and Latin America. Duke Energy has concentrations of receivables
from natural gas and electric utilities and their affiliates, as well as
industrial customers throughout these regions. These concentrations of customers
may affect Duke Energy's overall credit risk in that certain customers may be
similarly affected by changes in economic, regulatory or other factors. Where
exposed to credit risk, Duke Energy analyzes the counterparties' financial
condition prior to entering into an agreement, establishes credit limits and
monitors the appropriateness of those limits on an ongoing basis. Duke Energy
frequently uses master collateral agreements to mitigate credit exposure. The
collateral agreement provides for a counterparty to post cash or letters of
credit for exposure in excess of the established threshold. The threshold amount
represents an open credit limit, determined in accordance with the corporate
credit policy. The collateral agreement also provides that the inability to post
collateral is sufficient cause to terminate a contract and liquidate all
positions.
The change in market value of NYMEX-traded futures and options contracts
requires daily cash settlement in margin accounts with brokers. Financial
derivatives are generally cash settled periodically throughout the contract
term. However, these transactions are also generally subject to margin
agreements with many of Duke Energy's counterparties.
As of December 31, 2001, Duke Energy had a pre-tax bad debt provision of $90
million related to receivables for energy sales in California. (See Current
Issues - California Issues.) Following the bankruptcy of Enron Corporation, Duke
Energy terminated substantially all contracts with Enron Corporation and its
affiliated companies (collectively, Enron). As a result, Duke Energy recorded,
as a charge, a non-collateralized accounting exposure of $43 million. The $43
million non-collateralized accounting exposure is comprised of charges of $24
million at Other Energy Services, $12 million at DENA, $3 million at
International Energy, $3 million at Field Services and $1 million at Natural Gas
Transmission. These amounts are stated on a pre-tax basis as charges against the
reporting segment's earnings.
The transactions between Enron and Duke Energy consisted of the following:
.. DENA and Other Energy Services - forward contracts, swaps, options and
physical contracts used to trade natural gas, power, crude oil, liquefied
petroleum gas and coal
.. International Energy - forward contracts and options used to trade and
hedge natural gas, power and oil
.. Field Services - physical purchase/sale contracts for natural gas and NGLs;
forward contracts, swaps and options used to trade natural gas and NGLs;
transportation and storage
.. Natural Gas Transmission - forward financial sales of NGLs
The $43 million charge was a direct reduction to earnings before income taxes
and was a result of charging the full amount of unsettled mark-to-market
earnings previously recognized, and all derivative assets and accounts
receivable that became impaired due to Enron's financial deterioration. All
assets written off or reserved for were net of the margin (cash collateral)
posted by Enron of $330 million and applied by Duke Energy in connection with
transactions between the companies.
Duke Energy's determination of its bankruptcy claims against Enron is still
under review, and its claims made in the bankruptcy case are likely to exceed
$43 million. Any bankruptcy claims that exceed this amount would primarily
relate to termination and settlement rights under contracts and transactions
with Enron that would have been recognized in future periods, and not in the
historical periods covered by the financial statements to which the $43 million
charge relates.
Substantially all contracts with Enron were completed or terminated prior to
December 31, 2001. Duke Energy has continuing contractual relationships with
certain Enron affiliates, which are not in bankruptcy. In Brazil, a power
purchase agreement between a Duke Energy affiliate, Paranapanema, and Elektro
23
Eletricidade e Servicos S/A (Elektro), a distribution company 40% owned by
Enron, will expire December 31, 2005. The contract was executed by Duke Energy's
predecessor in interest in Paranapanema, and obligates Paranapanema to provide
energy to Elektro on an irrevocable basis for the contract period. In addition,
a purchase/sale agreement expiring September 1, 2005 between a Duke Energy
affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint venture between
Enron and El Paso Corporation, continues to be in effect. The contract requires
the Duke Energy affiliate to provide liquefied natural gas to Citrus. Citrus has
provided a letter of credit in favor of Duke Energy to cover its exposure.
Interest Rate Risk
Duke Energy is exposed to risk resulting from changes in interest rates as a
result of its issuance of variable-rate debt, fixed-to-floating interest rate
swaps, commercial paper and auction market preferred stock. Duke Energy manages
its interest rate exposure by limiting its variable-rate and fixed-rate
exposures to certain percentages of total capitalization, as set by policy, and
by monitoring the effects of market changes in interest rates. Duke Energy also
enters into financial derivative instruments, including, but not limited to,
interest rate swaps, options, swaptions and lock agreements to manage and
mitigate interest rate risk exposure. (See Notes 1, 7, 10, 12 and 14 to the
Consolidated Financial Statements.)
Based on a sensitivity analysis as of December 31, 2001, it was estimated that
if market interest rates average 1% higher (lower) in 2002 than in 2001,
earnings before income taxes would decrease (increase) by approximately $57
million. Comparatively, based on a sensitivity analysis as of December 31, 2000,
had interest rates averaged 1% higher (lower) in 2001 than in 2000, it was
estimated that earnings before income taxes would have decreased (increased) by
approximately $53 million. These amounts include the effects of interest rate
hedges and were determined by considering the impact of the hypothetical
interest rates on the variable-rate securities outstanding as of December 31,
2001 and 2000. The increase in interest rate sensitivity is primarily due to the
increase in outstanding variable-rate commercial paper. If interest rates
changed significantly, management would likely take actions to manage its
exposure to the change. However, due to the uncertainty of the specific actions
that would be taken and their possible effects, the sensitivity analysis assumes
no changes in Duke Energy's financial structure.
Equity Price Risk
Duke Energy maintains trust funds, as required by the Nuclear Regulatory
Commission (NRC), to fund certain costs of nuclear decommissioning. (See Note 11
to the Consolidated Financial Statements.) As of December 31, 2001 and 2000,
these funds were invested primarily in domestic and international equity
securities, fixed-rate, fixed-income securities and cash and cash equivalents.
Duke Energy has an agreement with the NRC that these funds will only be used for
activities relating to nuclear decommissioning. Because the accounting for
nuclear decommissioning recognizes that costs are recovered through Franchised
Electric's rates, fluctuations in equity prices or interest rates do not affect
consolidated results of operations, cash flows or financial position. (See
Current Issues - Nuclear Decommissioning Costs.)
Foreign Currency Risk
Duke Energy is exposed to foreign currency risk from investments in
international affiliates and businesses owned and operated in foreign countries.
To mitigate risks associated with foreign currency fluctuations, when possible,
transactions are denominated in or indexed to the U.S. dollar and/or local
inflation rates, or investments may be hedged through debt denominated or issued
in the foreign currency. Duke Energy also uses foreign currency derivatives,
where possible, to manage its risk related to foreign currency fluctuations. To
monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis,
which measures the impact of devaluation of the foreign currencies to which it
has exposure.
As of December 31, 2001, Duke Energy's primary foreign currency rate exposures
were the Brazilian real, the Peruvian nuevo sol, the Australian dollar, the El
Salvadoran colon, the Argentine peso, the European euro and the Canadian dollar.
Based on a sensitivity analysis as of December 31, 2001, a 10% devaluation
24
in the currency exchange rate in any or all of these foreign currencies would be
insignificant to Duke Energy's Consolidated Statements of Income. Significant
devaluations may impact Duke Energy's Consolidated Balance Sheets by decreasing
the value of Duke Energy's net investments through a reduction in the cumulative
translation adjustment in OCI.
Since 1991, the Argentine peso has been pegged to the U.S. dollar at a fixed 1:1
exchange ratio. In December 2001, the Argentine government imposed a restriction
that limited cash withdrawals above a certain amount and foreign money
transfers. Financial institutions were allowed to conduct limited activity as a
bank and exchange holiday was announced, and currency exchange activity was
essentially halted. In January 2002, the Argentine government announced the
creation of a dual-currency system. Subsequently, however, the Argentine
government has decided to use a free-floating currency.
Duke Energy's investment in Argentina was U.S. dollar functional as of December
31, 2001. Once a functional currency determination has been made, that
determination must be adhered to consistently, unless significant changes in
economic factors indicate that the entity's functional currency has changed. The
recent events in Argentina require a change. In January 2002, the functional
currency of Duke Energy's investment in Argentina changed from the U.S. dollar
to the Argentine peso. In compliance with SFAS No. 52, "Foreign Currency
Translation," the change in functional currency will be made prospectively.
Management believes that the events in Argentina will have no material adverse
effect on Duke Energy's future consolidated results of operations, cash flows or
financial position.
Current Issues
Electric Competition. Wholesale Competition. The Energy Policy Act of 1992 and
the FERC's subsequent rulemaking activities opened the wholesale energy market
to competition. Open-access transmission for wholesale customers, as defined by
the FERC's rules, provides energy suppliers, including Duke Energy, with
opportunities to sell and deliver capacity and energy at market-based prices.
From the FERC's open-access rule, Franchised Electric obtained the rights to
sell capacity and energy at market-based rates from its own assets, which allows
Franchised Electric to purchase, at attractive rates, a portion of its capacity
and energy requirements resulting in lower overall costs to customers. Open
access also provides Franchised Electric's existing wholesale customers with
competitive opportunities to seek other suppliers for their capacity and energy
requirements.
In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding
Regional Transmission Organizations (RTOs). These orders set minimum
characteristics and functions RTOs must meet, including independent authority to
establish the terms and conditions of transmission service over the facilities
they control. The orders provide for an open and flexible RTO structure to meet
the needs of the market, and for the possibility of incentive ratemaking and
other benefits for transmission owners that participate.
As a result of these rulemakings, Duke Energy and two other investor-owned
utilities, Carolina Power & Light Company and South Carolina Electric & Gas
Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO
responsible for the control of the companies' combined transmission systems. In
March 2001, GridSouth received provisional approval from the FERC. However, in
July 2001, the FERC issued orders recommending that utilities throughout the
U.S. combine their transmission systems to create four large independent
regional operators, one each in the Northeast, Southeast, Midwest and West. The
FERC ordered GridSouth and other utilities in the Southeast to join in 45 days
of mediation to negotiate terms of a Southeast RTO. The FERC has not issued an
order specifically based on those proceedings.
Duke Energy, Carolina Power & Light Company and South Carolina Electric & Gas
Company remain committed to the GridSouth RTO, but due to regulatory
uncertainties in the RTO arena, the companies have withdrawn their applications
to the PSCSC and NCUC to transfer functional control of their electric
transmission assets to GridSouth. The companies intend to file new applications
before the state commissions in the near future, including a revised GridSouth
structure designed to meet the needs of
25
customers and regulators. Also, in January of 2002, GridSouth signed a
memorandum of understanding with the representatives of SeTrans Grid Company
(SeTrans), a group of investor-owned utilities and public power entities in
several southeastern states seeking to form an RTO, to cooperate in discussing
potential operational relationships between GridSouth and SeTrans and the
structure of wholesale electric markets in the southeast U.S.
The actual structure of GridSouth or an alternative combined transmission
structure and the date it will become operational depend upon the resolution of
all regulatory approvals and technical issues. Management believes that the
result of this process, and the establishment and operation of GridSouth or an
alternative combined transmission system structure, will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
Retail Competition. Currently, Franchised Electric operates as a vertically
integrated, investor-owned utility with exclusive rights to supply electricity
in a franchised service territory - a 22,000-square-mile service territory in
the Carolinas. In its retail business, the NCUC and the PSCSC regulate
Franchised Electric's service and rates.
Electric industry restructuring is being addressed throughout the U.S. and will
likely impact all entities owning electric generating assets. The NCUC and the
PSCSC are studying the merits of restructuring the electric utility industry in
the Carolinas. In 1997, North Carolina passed a bill that established a study
commission, including legislators, customers, utilities and a member of an
environmental group, to examine whether competition should be implemented in the
state. In 2000, the study commission unanimously approved a set of
recommendations on electric restructuring and submitted a report containing
these recommendations to the General Assembly. The report recommended retail
deregulation beginning partially in 2005 and fully in 2006. However, events in
California's power market have led the study commission to evaluate whether, and
to what extent, proposed legislation should be introduced. In general, the
commission has expressed interest in ensuring that a viable wholesale electric
market is in place prior to opening the state's retail electric market.
Currently, the electric utility industry is predominantly regulated on a basis
designed to recover the cost of providing electric power to customers. If
cost-based regulation were to be discontinued in the industry for any reason,
including competitive pressure on the cost-based prices of electricity, profits
could be reduced and electric utilities might be required to reduce their asset
balances to reflect a market basis less than cost. Discontinuance of cost-based
regulation would also require affected utilities to write off their associated
regulatory assets. Duke Energy's regulatory assets are included in the
Consolidated Balance Sheets. The portion of these regulatory assets related to
Franchised Electric is approximately $1.0 billion, including primarily purchased
capacity costs, deferred debt expense and deferred taxes related to regulatory
assets. Duke Energy is recovering substantially all of these regulatory assets
through its current wholesale and retail electric rates and may attempt to
continue to recover these assets during a transition to competition. In
addition, Duke Energy would seek to recover the costs of its electric generating
facilities in excess of the market price of power at the time of transition.
Duke Energy supports a properly managed and orderly transition to competitive
generation and retail services in the electric industry. However, transforming
the current regulated industry into efficient, competitive generation and retail
electric markets is a complex undertaking, which will require a carefully
considered transition to a restructured electric industry. The key to effective
retail competition is fairness among customers, service providers and investors.
Duke Energy intends to continue to work with customers, legislators and
regulators to address all the important issues. Management currently cannot
predict the impact, if any, of these competitive forces on future consolidated
results of operations, cash flows or financial position.
Natural Gas Competition. Wholesale Competition. In 2000, the FERC issued Order
637, which sets forth revisions to its regulations governing short-term natural
gas transportation services and policies governing the regulation of interstate
natural gas pipelines. "Short-term" has been defined as all transactions of less
than one year. Among the significant actions taken are the lifting of the price
cap for short-term capacity release by
26
pipeline customers for an experimental 2 1/2-year period ending September 1,
2002, and requiring interstate pipelines to file pro forma tariff sheets to (i)
provide for nomination equality between capacity release and primary pipeline
capacity; (ii) implement imbalance management services (for which interstate
pipelines may charge fees) while at the same time reducing the use of
operational flow orders and penalties; and (iii) provide segmentation rights if
operationally feasible. Order 637 also narrows the right of first refusal to
remove economic biases perceived in the current rule. Order 637 imposes
significant new reporting requirements for interstate pipelines that were
implemented by Duke Energy during 2000. Additionally, Order 637 permits
pipelines to propose peak/off-peak rates and term-differentiated rates, and
encourages pipelines to propose experimental capacity auctions. By Order 637-A,
issued in 2000, the FERC generally denied requests for rehearing and several
parties, including Duke Energy, have filed appeals in the District of Columbia
Court of Appeals seeking court review of various aspects of the Order. During
the third quarter of 2001, Duke Energy's interstate pipelines submitted revised
pro forma tariff sheets to update the filings originally submitted in 2000.
These filings are currently subject to review and approval by the FERC.
Management believes that the effects of these matters will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
Retail Competition. Changes in regulation to allow retail competition could
affect Duke Energy's natural gas transportation contracts with local natural gas
distribution companies. While natural gas retail deregulation is in the very
early stages of development, management believes the effects of this matter will
have no material adverse effect on Duke Energy's future consolidated results of
operations, cash flows or financial position.
Nuclear Decommissioning Costs. Estimated site-specific nuclear decommissioning
costs, including the cost of decommissioning plant components not subject to
radioactive contamination, total approximately $1.9 billion stated in 1999
dollars based on decommissioning studies completed in 1999 (studies are
completed every five years). Duke Energy contributes to an external
decommissioning trust fund and maintains an internal reserve to fund these
costs.
The balance of the external funds was $716 million as of December 31, 2001 and
$717 million as of December 31, 2000, and is reflected in the Consolidated
Balance Sheets as Nuclear Decommissioning Trust Funds (asset) and Nuclear
Decommissioning Costs Externally Funded (liability). The balance of the internal
reserve was $239 million as of December 31, 2001 and $231 million as of December
31, 2000, and is reflected in the Consolidated Balance Sheets as Accumulated
Depreciation and Amortization.
Both the NCUC and the PSCSC have granted Duke Energy recovery of estimated
decommissioning costs through retail rates over the expected remaining service
periods of its nuclear plants. Management believes that the decommissioning
costs being recovered through rates, when coupled with expected fund earnings,
are sufficient to provide for the cost of decommissioning. Additionally,
management believes that funding of the decommissioning costs will not have a
material adverse effect on consolidated results of operations, cash flows or
financial position. (See Note 11 to the Consolidated Financial Statements.)
The external decommissioning trust fund is invested primarily in domestic and
international equity securities, fixed-rate, fixed-income securities and cash
and cash equivalents. Duke Energy has an agreement with the NRC that these funds
will only be used for activities relating to nuclear decommissioning. These
investments are exposed to price fluctuations in equity markets and changes in
interest rates. Because the accounting for nuclear decommissioning recognizes
that costs are recovered through Franchised Electric's rates, fluctuations in
equity prices or interest rates do not affect consolidated results of
operations, cash flows or financial position.
Nuclear Relicensing. In 2000, the NRC renewed the operating license for Duke
Energy's three Oconee nuclear units through 2033 to 2034. Applications to renew
the operating licenses for Duke Energy's Catawba and McGuire nuclear units were
filed with the NRC in June 2001. These operating licenses currently expire
between 2021 and 2026.
27
Environmental. Duke Energy is subject to international, federal, state and local
regulations regarding air and water quality, hazardous and solid waste disposal
and other environmental matters.
Manufactured Gas Plants and Superfund Sites. Duke Energy operated manufactured
gas plants until the early 1950s and has entered into a cooperative effort with
the State of North Carolina and other owners of former manufactured gas plant
sites to investigate and, where necessary, remediate those contaminated sites.
Regulators consider Duke Energy to be a potentially responsible party, possibly
subject to future liability at six federal and two state Superfund sites. While
remediation costs may be substantial, Duke Energy will share in any liability
associated with contamination at these sites with other potentially responsible
parties. Management believes that resolution of these matters will have no
material adverse effect on consolidated results of operations, cash flows or
financial position.
PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In 2001, Texas
Eastern Transmission, LP, a wholly owned subsidiary of Duke Energy, completed
the remaining requirements of a 1989 U.S. Consent Decree regarding the cleanup
of PCB-contaminated sites. The Environmental Protection Agency (EPA) certified
the completion of all work under the Consent Decree in January 2002. Monitoring
of groundwater and remediation at certain sites may continue as required by
various state authorities.
In March 1999, Duke Energy sold PEPL and Trunkline to CMS. (See Note 1 to the
Consolidated Financial Statements for more information on the sale of the
pipelines.) Under the terms of the sales agreement with CMS, Duke Energy is
obligated to complete cleanup of previously identified contamination resulting
from the past use of PCB-containing lubricants and other discontinued practices
at certain sites on the PEPL and Trunkline systems.
Based on Duke Energy's experience to date and costs incurred for cleanup,
management believes the resolution of matters relating to the environmental
issues discussed above will have no material adverse effect on consolidated
results of operations, cash flows or financial position.
Air Quality Control. In 1998, the EPA issued a final rule on regional ozone
control that required 22 eastern states and the District of Columbia to revise
their State Implementation Plans (SIPs) to significantly reduce emissions of
nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various
states, industry and other interests, including Duke Energy and the states of
North Carolina and South Carolina. In 2000, the court upheld most aspects of the
EPA rule. The same court subsequently extended the compliance deadline for
implementation of emission reductions to May 31, 2004.
In 2000, the EPA finalized another ozone-related rule under Section 126 of the
Clean Air Act (CAA). Section 126 of the CAA has virtually identical emission
control requirements as the 1998 action, and specified a May 1, 2003 compliance
date. While the emission reduction requirements of the rule have been upheld in
court, the implementation date for the rule has been revised to May 2004 as a
result of a legal challenge and the resulting court order. Management estimates
that Duke Energy will spend from $500 million to $900 million in capital costs
for additional emission controls through 2007 to comply with the new EPA rules.
Both North Carolina and South Carolina have revised their SIPs in response to
the EPA's 1998 rule, and are awaiting EPA approval. Legislation was introduced
in the North Carolina General Assembly in 2001 and passed by the state Senate
that would require North Carolina electric utilities, including Duke Energy, to
make significant reductions in emissions of sulfur dioxide and nitrogen oxides
from coal-fired power plants over the next seven to 11 years. Management
estimates Duke Energy's cost of achieving the proposed emission reductions to be
approximately $1.5 billion. A provision in the proposed North Carolina
legislation allows Duke Energy to recover those costs from customers through an
environmental compliance expenditure-recovery factor that is separate from the
electric utility's base rates. If passed into law, the final provisions could be
significantly different from the proposal.
28
Emission control retrofits needed to comply with the new rules are large
technical, design and construction projects. These projects will be managed
closely to ensure the continuation of reliable electric service to Duke Energy's
customers throughout the projects and upon their completion.
In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a
complaint against Duke Energy in the U.S. District Court in Greensboro, North
Carolina, for alleged violations of the New Source Review (NSR) provisions of
the CAA. The EPA claims that 29 projects performed at 25 of Duke Energy's
coal-fired units were major modifications, as defined in the CAA, and that Duke
Energy violated the CAA's NSR requirements when it undertook those projects
without obtaining permits and installing emission controls for sulfur dioxide,
nitrogen oxide and particulate matter. The complaint asks the court to order
Duke Energy to stop operating the coal-fired units identified in the complaint,
install additional emission controls and pay unspecified civil penalties. This
complaint is part of the EPA's NSR enforcement initiative, in which the EPA
claims that utilities and others have committed widespread violations of the CAA
permitting requirements for the past 25 years. The EPA has sued or issued
notices of violation of investigative information requests to at least 48 other
electric utilities and cooperatives.
The EPA's allegations run counter to previous EPA guidance regarding the
applicability of the NSR permitting requirements. Duke Energy, along with other
utilities, has routinely undertaken the type of repair, replacement and
maintenance projects that the EPA now claims are illegal. Duke Energy believes
that all of its electric generation units are properly permitted and have been
properly maintained, and is defending itself vigorously against these alleged
violations. The U.S. Vice President's National Energy Policy Development Group
has ordered the EPA to review its NSR rules and has ordered the Department of
Justice to review the appropriateness of the enforcement cases. The EPA review
was scheduled to be completed by August 2001, but has not yet been concluded. In
January 2002, the Department of Justice released a report concluding that it was
not improper for the Department of Justice to initiate the enforcement cases
brought on behalf of the EPA. It specifically declined to address whether the
EPA's enforcement actions are wise as a matter of national energy policy.
Because these matters are in a preliminary stage, management cannot estimate the
effects of these matters on Duke Energy's future consolidated results of
operations, cash flows or financial position. The CAA authorizes civil penalties
of up to $27,500 per day per violation at each generating unit. Civil penalties,
if ultimately imposed by the court, and the cost of any required new pollution
control equipment, if the court accepts the EPA's contentions, could be
substantial.
Global Climate Change. In 1997, the United Nations held negotiations in Kyoto,
Japan, to determine how to minimize global warming. The resulting Kyoto Protocol
prescribed, among other greenhouse gas emission reduction tactics, carbon
dioxide emission reductions from fossil-fueled electric generating facilities in
the U.S. and other developed nations, as well as methane emission reductions
from natural gas operations. The high-level operational framework for
implementing the Kyoto Protocol was agreed to in November 2001. If the Kyoto
Protocol were to be implemented in developed countries where Duke Energy
operates, it could have far-reaching implications for Duke Energy and the entire
energy industry. However, the outcome and timing of these implications are
highly uncertain, and Duke Energy cannot estimate the effects on future
consolidated results of operations, cash flows or financial position. Duke
Energy remains engaged in discussions with those developing public policy
initiatives and continuously assesses the commercial implications for its
markets around the world.
Notice of Proposed Rulemaking (NOPR). On September 27, 2001, the FERC issued a
NOPR announcing that it is considering new regulations regarding standards of
conduct that would apply uniformly to natural gas pipelines and electric
transmitting public utilities that are currently subject to different gas or
electric standards. The proposed standards would change how companies and their
affiliates interact and share information by broadening the definition of
"affiliate" covered by the standards of conduct, from the more narrow definition
in the existing regulations. The NOPR also seeks comment on whether the
standards of conduct should be broadened to include the separation of those
involved in the bundled retail electric sales function from those in the
transmission function, as the current standards apply only to those involved in
wholesale activities. Various entities filed comments on the NOPR with the FERC,
including Duke Energy which filed on December 20, 2001. The FERC has indicated
that they appreciate the complexity of the
29
issues and that they would prefer having a technical conference before entering
directly into a final rulemaking. No notice of a technical conference has been
given at this time.
Regulatory Matters. In 2001, the NCUC and PSCSC began a joint investigation,
along with the Public Staff of the NCUC, regarding certain Duke Power regulatory
accounting entries for 1998. In its internal review of the 14 entries in
question, Duke Energy concluded that nine items were correctly classified for
regulatory accounting. Four items were incorrectly classified for regulatory
purposes for 1998 only, and did not recur. The classification of the remaining
item, distributions from a mutual insurance company, is subject to differing
regulatory interpretations. Duke Energy believes this item was appropriately
classified, but is evaluating its classification for future years. As part of
their investigation, the NCUC and PSCSC have jointly engaged an independent firm
to conduct an audit of Duke Power's accounting records for reporting periods
from 1998 through June 30, 2001. Duke Energy continues to fully cooperate with
the commissions in their investigation. As requested by the NCUC, Duke Energy
has recorded the 2001 mutual insurance distribution, approximately $33 million,
in a deferred credit account on the Consolidated Balance Sheets, pending final
outcome of the independent audit.
California Issues. Duke Energy, some of its subsidiaries and three current or
former executives have been named as defendants, among other corporate and
individual defendants, in one or more of a total of six lawsuits brought by or
on behalf of electricity consumers in the State of California. The plaintiffs
seek damages as a result of the defendants' alleged unlawful manipulation of the
California wholesale electricity markets. DENA and DETM are among 16 defendants
in a class-action lawsuit (the Gordon lawsuit) filed against generators and
traders of electricity in California markets. DETM was also named as one of
numerous defendants in four additional lawsuits, including two class actions
(the Hendricks and Pier 23 Restaurant lawsuits), filed against generators,
marketers, traders and other unnamed providers of electricity in California
markets. A sixth lawsuit (the Bustamante lawsuit) was brought by the Lieutenant
Governor of the State of California and a State Assemblywoman, on their own
behalf as citizens and on behalf of the general public, and includes Duke
Energy, some of its subsidiaries and three current or former executives of Duke
Energy among other corporate and individual defendants. The Gordon and Hendricks
class-action lawsuits were filed in the Superior Court of the State of
California, San Diego County, in November 2000. Three other lawsuits were filed
in January 2001, one in Superior Court, San Diego County, and the other two in
Superior Court, County of San Francisco. The Bustamante lawsuit was filed in May
2001 in Superior Court, Los Angeles County. These lawsuits generally allege that
the defendants manipulated the wholesale electricity markets in violation of
state laws against unfair and unlawful business practices and state antitrust
laws. The plaintiffs seek aggregate damages of billions of dollars. The lawsuits
seek the refund of alleged unlawfully obtained revenues for electricity sales
and, in four lawsuits, an award of treble damages. These suits have been
consolidated before a state court judge in San Diego. While these matters are in
their earliest stages, management believes, based on its analysis of the facts
and the asserted claims, that their resolution will have no material adverse
effect on Duke Energy's consolidated results of operations, cash flows or
financial position.
In addition to the lawsuits, several investigations and regulatory proceedings
at the state and federal levels are looking into the causes of high wholesale
electricity prices in the western U.S. At the federal level, numerous
proceedings are before the FERC. Some parties to those proceedings have made
claims for billions of dollars of refunds from sellers of wholesale electricity,
including DETM. Some parties have also sought to revoke the authority of DETM
and other DENA-affiliated electricity marketers to sell electricity at
market-based rates. The FERC is also conducting its own wholesale pricing
investigation. As a result, the FERC has ordered some sellers, including DETM,
to refund, or to offset against outstanding accounts receivable, amounts billed
for electricity sales in excess of a FERC-established proxy price. The proxy
price represents what the FERC believes would have been the market-clearing
price in a perfectly competitive market. In June 2001, DETM offset approximately
$20 million against amounts owed by the California Independent System Operator
and the California Power Exchange for electricity sales during January and
February 2001. This offset reduced the $110 million reserve established in 2000
to $90 million. Proceedings are ongoing to determine, among other issues, the
amount of any refunds or offsets for periods prior to January 2001, and the
method to be used to determine the proxy price in future months.
30
At the state level, the California Public Utilities Commission is conducting
formal and informal investigations to determine if power plant operators in
California, including some Duke Energy entities, have improperly "withheld,"
either economically or physically, generation output from the market to
manipulate market prices. In addition, the California State Senate formed a
Select Committee to Investigate Price Manipulation of the Wholesale Energy
Market (Select Committee). The Select Committee has served a subpoena on Duke
Energy and some of its subsidiaries seeking data concerning their California
market activities. The Select Committee has heard testimony from several
witnesses but no one from Duke Energy has yet been subpoenaed to testify.
The California Attorney General is also conducting an investigation to determine
if any market participants engaged in illegal activity, including antitrust
violation, in the course of their electricity sales into wholesale markets in
the western U.S. The Attorneys General of Washington and Oregon are
participating in the California Attorney General's investigation. The San Diego
District Attorney is conducting a separate investigation into market activities
and has issued subpoenas to DETM and a DENA subsidiary.
The California Attorney General has also convened a grand jury to determine
whether criminal charges should be brought against any market participants. To
date, no Duke Energy employee has been called to testify before the grand jury
nor have any criminal charges been filed against Duke Energy or any of its
officers, directors or employees in connection with the wholesale electricity
markets in the states of the western U.S.
Throughout 2001, Duke Energy conducted its business in California to supply the
maximum possible electricity to meet the needs of the state, limit its exposure
to non-creditworthy counterparties and manage the output limitations on its
power plants imposed by applicable permits and laws. Since December 31, 2000,
Duke Energy has closely managed the balance of doubtful receivables, and
believes that the current pre-tax bad debt provision of $90 million is
appropriate. No additional provisions for California receivables were recorded
in 2001. Management believes, based on its analysis of the facts and the
asserted claims, that the resolution of these matters will have no material
adverse effect on Duke Energy's consolidated results of operations, cash flows
or financial position.
Litigation and Contingencies. Exxon Mobil Corporation Arbitration. In 2000,
three Duke Energy subsidiaries initiated binding arbitration against three Exxon
Mobil Corporation subsidiaries (the Exxon Mobil entities) concerning the
parties' joint ownership of DETM and related affiliates (the Ventures). At issue
is a buy-out right provision under the joint venture agreements for these
entities. If there is a material business dispute between the parties, which
Duke Energy alleges has occurred, the buy-out provision gives Duke Energy the
right to purchase Exxon Mobil's 40% interest in DETM. Exxon Mobil does not have
a similar right under the joint venture agreements and once Duke Energy
exercises the buy-out right, each party has the right to "unwind" the buy-out
under certain specific circumstances. In December 2000, Duke Energy exercised
its right to buy the Exxon Mobil entities' interest in the Ventures. Duke Energy
claims that refusal by the Exxon Mobil entities to honor the exercise is a
breach of the buy-out right provision, and seeks specific performance of the
provision. Duke Energy has also made additional claims against the Exxon Mobil
entities for breach of the agreements governing the Ventures.
In January 2001, the Exxon Mobil entities made counterclaims in the arbitration
and, in a separate Texas state court action, alleged that Duke Energy breached
its obligations to the Ventures and to the Exxon Mobil entities. In April 2001,
the state court stayed its action, compelling the Exxon Mobil entities to
arbitrate their claims. The Exxon Mobil entities proceeded with the arbitration
of their claims and have not challenged this order in an appellate court. In
early October 2001, the arbitration panel convened an evidentiary hearing
regarding the buy-out right provision and Duke Energy's and Exxon Mobil's claims
against each other. The panel has not yet ruled but Duke Energy expects a final
decision from the panel in early 2002. Management believes that the final
disposition of this action will have no material adverse effect on Duke Energy's
consolidated results of operations or financial position.
31
Duke Energy and its subsidiaries are involved in other legal, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding performance, contracts and other matters arising in the
ordinary course of business, some of which involve substantial amounts.
Management believes that the final disposition of these proceedings will have no
material adverse effect on consolidated results of operations, cash flows or
financial position. (See Notes 15 and 21) to the Consolidated Financial
Statements for information concerning litigation and other commitments and
contingencies.)
New Accounting Standards. In June 2001, the FASB issued SFAS No. 141, "Business
Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets."
SFAS No. 141 requires that all business combinations initiated (as defined by
the standard) after June 30, 2001 be accounted for using the purchase method.
Companies may no longer use the pooling method of accounting for future
combinations.
Duke Energy adopted SFAS No. 142, "Goodwill and Other Intangible Assets," as of
January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over
an estimated useful life, as previously required. Instead, goodwill amounts are
subject to a fair-value-based annual impairment assessment. Duke Energy did not
recognize any material impairment due to the implementation of SFAS No. 142. The
standard also requires certain identifiable intangible assets to be recognized
separately and amortized as appropriate upon reassessment. No adjustments to
intangibles were identified by Duke Energy at transition.
32
The following table shows what net income and earnings per share would have been
if amortization (including any related tax effects) related to goodwill that is
no longer being amortized had been excluded from prior periods.
=================================================================================================
Goodwill - Adoption of SFAS No. 142 (in millions, except per share amounts)
=================================================================================================
For the years ended December 31,
---------------------------------------
2001 2000 1999
---------------------------------------
Earnings Available for Common Stockholders
Earnings Available for Common Stockholders
Before Extraordinary Item and
Cumulative Effect of Change in
Accounting Principle $ 1,980 $ 1,757 $ 827
Extraordinary Gain, net of tax - - 660
Cummulative Effect of Change in
Accounting Principle, net of tax (96) - -
---------------------------------------
Reported Earnings Available for Common
Stockholders 1,884 1,757 1,487
Add back: Goodwill amortization, net of tax 75 56 39
---------------------------------------
Adjusted Earnings Available for Common
Stockholders $ 1,959 $ 1,813 $ 1,526
---------------------------------------
Basic earnings per share (before
extraordinary item and cumulative effect
of change in accounting principle)
Reported earnings per share $ 2.58 $ 2.39 $ 1.13
Goodwill Amortization 0.10 0.07 0.05
---------------------------------------
Adjusted earnings per share $ 2.63 $ 2.46 $ 1.18
Diluted earnings per share (before
extraordinary item and cumulative effect
of change in accounting principle)
Reported earnings per share $ 2.56 $ 2.38 $ 1.13
Goodwill Amortization 0.10 0.07 0.05
---------------------------------------
Adjusted earnings per share $ 2.66 $ 2.45 $ 1.18
Basic earnings per share
Reported earnings per share $ 2.45 $ 2.39 $ 2.04
Goodwill amortization 0.10 0.07 0.05
---------------------------------------
Adjusted earnings per share $ 2.55 $ 2.46 $ 2.09
Diluted earnings per share
Reported earnings per share $ 2.44 $ 2.38 $ 2.03
Goodwill amortization 0.10 0.07 0.05
---------------------------------------
Adjusted earnings per share $ 2.54 $ 2.45 $ 2.08
============================================================================================
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 provides the accounting requirements for retirement
obligations associated with tangible long-lived assets. It is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted.
Duke Energy is currently assessing the new standard and has not yet determined
the impact on its consolidated results of operations or financial position.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of." The new rules retain many of the fundamental recognition and
measurement provisions, but significantly change the criteria for classifying an
asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001. Duke Energy
33
has evaluated the new standard, and management believes that it will have no
material adverse effect on Duke Energy's consolidated results of operations or
financial position.
In June 2002, the FASB's EITF reached a partial consensus on Issue No. 02-03,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities." The EITF concluded that, effective for periods ending after July
15, 2002, mark-to-market gains and losses on energy trading contracts (including
those to be physically settled) must be shown on a net basis in the Consolidated
Statements of Income. Duke Energy had previously chosen to report certain of its
energy trading contracts on a gross basis, as sales in operating revenues and
the associated costs recorded in operating expenses, in accordance with
prevailing industry practice. The amounts in the comparative Consolidated
Statements of Income have been reclassified to conform to the 2002 presentation.
The following table shows the impact of changing from gross to net presentation
for energy trading activities on Duke Energy's revenues (offsetting adjustments
were made to operating expenses resulting in no impact on net income or cash
flow from operations). In the derivation of net revenues, Duke Energy has
continued to enhance its methodologies around the application of this complex
accounting literature since the third quarter of 2002, when these revenues were
first reported on a net basis. See footnote 1 to the attached Consolidated
Financial Statements for further discussion.
- ------------------------------------------------------------------------------------------------
Revenues - Implementation of Gross vs. Net Presentation in EITF Issue No. 02-03 (in millions)
- ------------------------------------------------------------------------------------------------
For the years ended December
-------------------------------------------------
2001 2000 1999
---------------------------------------------
Total revenues before adjustment $ 59,503 $ 49,318 $ 21,766
Adjustment (40,974) (32,030) (11,387)
---------------------------------------------
Revenues as reported $ 18,529 $ 17,288 $ 10,379
============================================================================================
Energy Industry and Accounting Practices. The energy industry landscape changed
during 2001. The bankruptcy of Enron (See Quantitative and Qualitative
Disclosures About Market Risk - Credit Risk), the tragic events of September 11,
2001 and the global economic downturn will likely have continued impacts on the
industry.
Near-term economic growth is likely to be lower and more cyclical than in the
recent past. As a result, industrial or commercial customers and trading
counterparties could reduce their business volume with Duke Energy. However,
overall demand for power is still on the rise. Current estimates place demand
growth for power between 1% and 2% annually over the next decade. Duke Energy
will continue to seek opportunities to reduce the risks associated with economic
impacts on its customers, and help markets achieve desired supply/demand
equilibrium and infrastructure reliability.
The situation surrounding Enron's bankruptcy has forced regulators and
legislators to take a renewed look at accounting practices, financial
disclosures, companies' relationships with their independent auditors and
retirement plan practices. Duke Energy cannot predict the ultimate impact of any
future changes in laws or regulations. However, Duke Energy is committed to
complying with all laws and regulations and will continue to play an active role
in helping to shape future laws and regulations as they evolve.
Subsequent Events. On January 31, 2002, Duke Energy announced the planned sale
of its DE&S business unit to Framatome ANP, Inc. (a nuclear supplier) for
approximately $84 million. Two components of DE&S are not part of the sale. Duke
Energy will establish Duke Energy - Energy Delivery Services, formed by the
power delivery services component of DE&S, which will continue to supply power
delivery solutions to customers. Leadership of the U.S. Department of Energy
Mixed Oxide Fuel project will also remain with Duke Energy. The transaction will
require a Hart Scott Rodino filing and is expected to close in the second
quarter of 2002.
On March 13, 2002, Duke Energy announced the planned sale of DukeSolutions to
Ameresco. Inc. Duke Energy expects to close the transaction during the second
quarter of 2002, and record a loss of approximately $20 million.
34
On March 14, 2002, Duke Energy acquired Westcoast for approximately $8 billion,
including the assumption of debt. Westcoast, headquartered in Vancouver, British
Columbia, is a North American energy company with interests in natural gas
gathering, processing, transmission, storage and distribution, as well as power
generation and international energy businesses. In the transaction, a Duke
Energy subsidiary acquired all of the outstanding common shares of Westcoast in
exchange for approximately 49.9 million shares of Duke Energy common stock
(including exchangeable shares of a Duke Energy Canadian subsidiary that are
substantially equivalent to and exchangeable on a one-for-one basis for Duke
Energy common stock), and approximately $1.8 billion in cash. Under proration
provisions that ensure that approximately 50% of the total consideration is paid
in cash and 50% in stock, each common share of Westcoast entitled the holder to
elect to receive $43.80 in cash (Canadian), .7711 of a share of Duke Energy
common stock or of an exchangeable share of a Duke Energy Canadian subsidiary,
or a combination thereof. The cash portion of the consideration was funded with
the proceeds from the issuance of $750 million in Equity Units in November 2001
(See Financing Cash Flows) along with incremental commercial paper. Duke Energy
plans to retire the commercial paper later in 2002 and replace it with permanent
capital in the form of mandatory convertible equity. The timing for the
mandatory convertible equity will be dependent on the opportunities presented
and favorable market conditions. The Westcoast acquisition was accounted for
using the purchase method of accounting.
Debt
During 2002, Duke Energy issued $2,110 million of senior unsecured notes: $750
million of 6.25% senior unsecured notes due in 2012, $250 million of floating
rate (based on the three-month LIBOR plus 0.35%) senior unsecured notes due in
2005, $250 million of 6.60% retail senior unsecured notes due in 2022 (swapped
to floating rate based on the three-month LIBOR), $350 million of 6.45% senior
unsecured notes due in 2032, $110 million of 4.61% senior unsecured notes due in
2007 and $400 million of 5.625% senior unsecured notes due in 2012. In addition,
Duke Energy refinanced $250 million of senior unsecured debt with a short-term
private debt securities offering. The proceeds from these issuances were used
primarily for general corporate purposes, to repay the $250 million of private
debt securities, to redeem $100 million of Duke Energy's 7.5% Series B First and
Refunding Mortgage Bonds due in 2025, to retire $250 million of senior unsecured
debt, and to repay commercial paper. Related to the repayment of the $250
million of private debt securities, Duke Energy paid approximately $43 million
to buy back a remarketing option, the cost of which will be amortized over the
life of $350 million of 6.45% senior unsecured notes.
In 2002, Duke Capital Corporation issued $500 million of 6.25% senior unsecured
notes due in 2013 and $250 million of 6.75% senior unsecured notes due in 2032.
In addition, Duke Capital Corporation, through private placement transactions,
issued $500 million of floating rate (based on the one-month LIBOR plus 0.65%)
senior unsecured notes due in 2003 and $100 million of floating rate (based on
the one-month LIBOR plus 0.85%) senior unsecured notes due in 2004. The proceeds
from these issuances were used for general corporate purposes and to repay
commercial paper. Additionally, Duke Capital Corporation decreased its note
payable to D/FD by $286 million, to $282 million as of December 31, 2002. The
weighted-average interest rate on this note for 2002 was 2.5%. (See Notes 8 and
10.)
In 2002, a wholly owned subsidiary of Duke Energy, Duke Australia Pipeline
Finance Pty Ltd., closed a syndicated bank debt facility for $450 million with
various banks to fund its pipeline and power businesses in Australia. The
facility is split between a Duke Capital Corporation-guaranteed tranche and a
non-recourse project finance tranche that is secured by liens over existing
Australian pipeline assets. Proceeds from the project finance tranche were used
to repay intercompany loans.
During 2002, Texas Eastern Transmission, LP, issued $300 million of 5.25% senior
unsecured notes due in 2007 and $450 million of 7.0% senior unsecured notes due
in 2032. The proceeds from these issuances were used for general corporate
purposes, including the repayment of debt which matured in July 2002, and for
pipeline expansion and maintenance projects.
In 2002, Algonquin Gas Transmission Company, a wholly owned subsidiary of Duke
Energy, through a private placement transaction, issued $300 million of 5.69%
senior unsecured notes due in 2012. The
35
proceeds from this issuance are to be used for general corporate purposes,
including repayment of maturing debt, and for pipeline expansion and maintenance
projects.
In 2002, East Tennessee Natural Gas Company, a wholly owned subsidiary of Duke
Energy, through a private placement transaction, issued $150 million of 5.71%
senior unsecured notes due in 2012. The proceeds from this issuance were used
for general corporate purposes, including repayment of maturing corporate debt
and for pipeline expansion and maintenance projects.
During 2002, Union Gas Limited, a wholly owned subsidiary of Duke Energy and
Westcoast, issued 200 million Canadian dollars of 5.19% debentures due in 2007.
The proceeds from this issuance were used for general corporate purposes,
including the repayment of maturing debt, the repayment of commercial paper and
funding of capital expenditures.
In 2000, Catawba, a consolidated entity of Duke Energy, issued $1,025 million of
preferred member interests to a third-party investor. The proceeds from the
non-controlling investor were reflected on the Consolidated Balance Sheets as
Minority Interest in Financing Subsidiary and were subsequently advanced to
DEPG, a wholly owned subsidiary of Duke Energy. In September 2002, Catawba
distributed the receivable from DEPG to the preferred member, which
simultaneously withdrew its interest. As a result, the $1,025 million that DEPG
previously owed to Catawba became an obligation to the third-party investor and
was reclassified on the September 30, 2002 Consolidated Balance Sheet to
Long-term Debt. In October 2002, Duke Energy purchased the equity interests in
the third party investor and effectively reduced the debt to $994 million.
Additionally, Duke Capital Corporation financially guaranteed the $994 million
in return for certain modifications to the terms of the credit agreement.
On March 14, 2002, Duke Energy acquired Westcoast for approximately $8 billion,
including the assumption of $4.7 billion of debt. The assumed debt consists of
debt of Westcoast, Union Gas Limited (a wholly-owned subsidiary of Westcoast)
and various project entities that are wholly owned or consolidated by Duke
Energy. The interest rates on the assumed debt range from 1.8% to 15.0%, with
maturity dates ranging from 2002 through 2031.
Preferred and Preference Stock
In 2002 Duke Energy redeemed all of its Auction Series A preferred stock. The
total redemption price was approximately $75 million.
Equity Offering
In October 2002, Duke Energy issued 54.5 million shares of common stock at
$18.35 in a public offering. The proceeds from the offering were approximately
$1.0 billion, before underwriting commissions and other offering expenses, and
are being used to repay commercial paper previously issued to fund a portion of
the consideration for the Westcoast acquisition.
Regulatory Matters
In 2001, the NCUC and the PSCSC began a joint investigation, along with the
Public Staff of the NCUC, regarding certain Duke Power regulatory accounting
entries for 1998, including the classification of nuclear insurance
distributions. As part of their investigation, the NCUC and PSCSC jointly
engaged an independent firm to conduct an accounting investigation of Duke
Power's accounting records for reporting periods from 1998 through June 30,
2001. In the fourth quarter of 2002, Duke Power entered into a settlement
agreement with the NCUC and PSCSC, in which the parties agreed to changes
primarily related to nuclear insurance distributions, a one-time $25 million
credit to Duke Power's deferred fuels account for the benefit of North Carolina
and South Carolina customers, and the reclassification of $52 million of $58
million held in a suspense account to a nuclear insurance operation reserve
account. The remaining $6 million would be credited to income, which resulted in
a net $19 million pre-tax charge in fourth quarter 2002. The Carolina Utilities
Customer Association, a group that represents industrial customers in regulatory
proceedings before the NCUC, has appealed the decision to the North Carolina
court of appeals. In February 2003, Duke Energy received a Western District of
North Carolina Grand Jury subpoena for documents related to the audit by the
NCUC and the PSCSC of Duke Power regulatory reporting from 1998 to 2000. Duke
Energy intends to fully cooperate with the government in connection with this
investigation.
36
In October 2002, Duke Energy entered into a $240 million stock purchase
agreement with National Fuel Gas Company pursuant to which National Fuel will
acquire Duke Energy's Empire State Pipeline. The Empire State Pipeline, a
natural gas pipeline that originates at the U.S./Canada border and extends into
New York, was acquired by Duke Energy as part of the Westcoast acquisition in
March 2002 (See Note 2). The transaction, which was subject to a number of
conditions including certain regulatory approvals, was finalized in February
2003.
Commitments and Contingencies
Western Power Disputes. California Litigation. Duke Energy, some of its
subsidiaries and three current or former executives have been named as
defendants, along with numerous other corporate and individual defendants, in
one or more of a total of 15 lawsuits, filed in California on behalf of
purchasers of electricity in the State of California, with one suit filed on
behalf of a Washington State electricity purchaser. Most of these lawsuits seek
class action certification and damages, and other relief, as a result of the
defendants' alleged unlawful manipulation of the California wholesale
electricity markets. These lawsuits generally allege that the defendants
manipulated the wholesale electricity markets in violation of state laws against
unfair and unlawful business practices and, in some suits, in violation of state
antitrust laws. Plaintiffs in these lawsuits seek aggregate damages of billions
of dollars. The lawsuits seek the restitution and/or disgorgement of alleged
unlawfully obtained revenues for sales of electricity and, in some lawsuits, an
award of treble damages for alleged violations of state antitrust laws.
The first six of these lawsuits were filed in late 2000 through mid-2001 and
were consolidated before a single judge in San Diego. The plaintiffs in the six
lawsuits filed a joint Master Amended Complaint in March 2002, which added
additional defendants. The claims against the additional defendants are similar
to those in the original complaints. In April 2002, some defendants, including
Duke Energy, filed cross-complaints against various market participants not
named as defendants in the plaintiffs' original and amended complaints. In May
2002, certain cross-defendants removed these actions to federal court in San
Diego.
The other nine of these 15 suits were filed in mid- to late 2002. The state
court suits have been removed to federal court, and all suits have been
transferred to federal court in San Diego for pre-trial consolidation with the
previously filed six lawsuits. Various motions are pending before the courts,
including motions concerning the jurisdiction of the courts and motions to
dismiss claims of the parties. In December 2002, the court ordered the remand of
the original six suits, and certain defendants and cross-defendants have
appealed that ruling.
On January 6, 2003, the federal court in San Diego granted the motion of the
defendants to dismiss the suit filed by the Washington state plaintiff. The
court ruled that the plaintiff's state law claims, including alleged violations
of the California antitrust and unfair business practices laws, were barred on
filed rate and federal preemption grounds.
Related Oregon and Washington Litigation. On December 16 and December 20, 2002,
respectively, plaintiffs filed class action suits against Duke Energy and
numerous other energy companies in state court in Oregon and in federal court in
Washington making allegations similar to those in the California suits.
Plaintiffs allege they paid unreasonably high prices for electricity and/or
natural gas during the time period from January 2000 to the present as a result
of defendants' activities which were fraudulent, negligent, and in violation of
each state's business practices laws. Among other things, they seek damages, an
order from the court prohibiting the defendants from engaging in the alleged
unlawful acts complained of, and an accounting of the transactions entered into
for the purchase and sale of wholesale energy.
Trade publications. On November 20, 2002, the Lieutenant Governor of the State
of California, on behalf of himself, the general public and taxpayers of
California, filed a class action suit against the publisher of
37
natural gas trade publications and numerous other defendants, including seven
Duke Energy entities, in state court in Los Angeles alleging that the defendants
engaged in various unlawful acts, including artificially inflating the index
prices of natural gas reported in industry publications through collusive
behavior, and have thereby violated state business practices laws. The
plaintiffs seek an order prohibiting the defendants from engaging in the acts
complained of, restitution, disgorgement of profits acquired through defendants'
alleged unlawful acts, an award of civil fines, compensatory and punitive
damages in unspecified amounts, and other appropriate relief.
Other proceedings. In addition to the lawsuits, several investigations and
regulatory proceedings at the state and federal levels are looking into the
causes of high wholesale electricity prices in the western U.S during 2000 and
2001. At the federal level, numerous proceedings are before the FERC. Some
parties to those proceedings have made claims for billions of dollars of refunds
from sellers of wholesale electricity, including Duke Energy Trading and
Marketing, L.L.C. (DETM). Some parties have also sought to revoke the authority
of DETM and other DENA-affiliated electricity marketers to sell electricity at
market-based rates. The FERC is also conducting its own wholesale pricing
investigation. As a result, the FERC has ordered some sellers, including DETM,
to refund, or to offset against outstanding accounts receivable, amounts billed
for electricity sales in excess of a FERC-established proxy price. The proxy
price represents what the FERC believes would have been the market-clearing
price in a perfectly competitive market. In June 2001, DETM offset approximately
$20 million against amounts owed by the California Independent System Operator
(CAISO) and the California Power Exchange (CalPX) for electricity sales during
January and February 2001. This offset reduced the $110 million reserve
established in 2000 to $90 million. Since December 31, 2000, Duke Energy has
closely managed the balance of doubtful receivables, and believes that the
current pre-tax bad debt provision of $90 million is appropriate. No additional
provisions for California receivables were recorded in 2001 or 2002.
In December 2002, the presiding administrative law judge in the FERC refund
proceedings issued his proposed findings with respect to the mitigated market
clearing price, including his preliminary determinations of the refund liability
of each seller of electricity in the CAISO and CalPX. These proposed findings
estimate that DETM has refund liability of approximately $95 million in the
aggregate to both the CAISO and CalPX. This would be offset against the
remaining receivables still owed to DETM by the CAISO and CalPX. The proposed
findings are the presiding judge's estimates only and are still subject to
further recalculation and adoption by the FERC in connection with its ongoing
wholesale pricing investigation.
At the state level, the California Public Utilities Commission is conducting
formal and informal investigations to determine if power plant operators in
California, including some Duke Energy entities, have improperly "withheld,"
either economically or physically, generation output from the market to
manipulate market prices. In addition, the California State Senate formed a
Select Committee to Investigate Price Manipulation of the Wholesale Energy
Market (Select Committee). The Select Committee served a subpoena on Duke Energy
and some of its subsidiaries seeking data concerning their California market
activities. The Select Committee heard testimony from several witnesses but no
one from Duke Energy has been subpoenaed to testify.
The California Attorney General is also conducting an investigation to determine
if any market participants engaged in illegal activity, including antitrust
violations, in the course of their electricity sales into wholesale markets in
the western U.S. The Attorneys General of Washington and Oregon are
participating in the California Attorney General's investigation. The San Diego
District Attorney is conducting a separate investigation into market activities
and issued subpoenas to DETM and a DENA subsidiary.
The U.S. Attorney's Office in San Francisco served a grand jury subpoena on Duke
Energy in November 2002 seeking, in general, information relating to possible
manipulation of the electricity markets in California, including potential
antitrust violations. As with the other ongoing investigations related to the
California electricity markets, Duke Energy is cooperating with the U.S.
Attorney's Office in connection with its investigation.
38
Sacramento Municipal Utility District (SMUD) and City of Burbank, California
FERC Complaints. On July 24, 2002 and August 12, 2002, respectively, the
Sacramento Municipal Utility District and the City of Burbank, California filed
complaints with the FERC against DETM and other providers of wholesale energy
requesting that the FERC mitigate alleged unjust and unreasonable prices in
sales contracts entered into between DETM and the complainants in the first
quarter of 2001. The complainants, alleging that DETM had the ability to
exercise market power, claim that the contract prices are unjust and
unreasonable because they were entered into during a period that the FERC
determined the western markets to be dysfunctional and uncompetitive and that
the western markets influenced their price. In support of their request to
mitigate the contract price, the complainants rely on the fact that the contract
prices are higher than prices in the West following implementation of the FERC's
June 2001 price mitigation plan. The complainants request the FERC to set "just
and reasonable" contract rates and to promptly set a refund effective date. On
September 18, 2002, the FERC issued an order in the Sacramento matter setting
forth, in part, that this matter be set for an evidentiary hearing to be held in
abeyance until the parties engage in settlement negotiations, that the parties
be required to participate in settlement negotiations, and that a refund
effective date of September 22, 2002 be established. DETM participated in
settlement proceedings and reached a settlement with SMUD in early February
2003. On February 7, 2003, SMUD filed to withdraw its FERC complaint against
DETM. The FERC has not yet issued an order in the City of Burbank proceeding.
Colorado River Commission of Nevada (CRCN) /Pioneer Companies (Pioneer). The
State of Nevada, through the CRCN, filed an "interpleader" complaint in federal
court in Nevada on July 9, 2002, against Pioneer and 13 vendors, including DETM,
who entered into power transactions with the CRCN between January 1998 and the
filing date of the suit. The CRCN alleges that it purchased power on behalf of
Pioneer but that Pioneer has disavowed its contractual liability to pay for
certain of those power transactions. The CRCN asserts that DETM and the other
vendors may have claims for the value of their contracts with the CRCN in excess
of $100 million. The CRCN asks the court to assess the competing claims of the
parties and distribute the assets which it seeks to deposit into the registry of
the court (cash assets of approximately $35 million allegedly held for Pioneer's
behalf as well as the value of electric power delivered or to be delivered on
Pioneer's behalf) and issue other appropriate orders to resolve the claims while
prohibiting the institution or prosecution of other proceedings affecting the
claims at issue. DETM and certain other parties have filed motions to dismiss
the complaint on various grounds.
Management believes, based on its analysis of the facts and the asserted claims,
that the resolution of these Western Power Disputes will have no material
adverse effect on Duke Energy's consolidated results of operations, cash flows
or financial position.
Exxon Mobil Corporation Arbitration. In 2000, three Duke Energy subsidiaries
initiated binding arbitration against three Exxon Mobil Corporation subsidiaries
(the Exxon Mobil entities) concerning the parties' joint ownership of DETM and
related affiliates (the Ventures). At issue was a buy-out right provision under
the joint venture agreements for these entities. If there is a material business
dispute between the parties, which Duke Energy alleged had occurred, the buy-out
provision gives Duke Energy the right to purchase Exxon Mobil's 40% interest in
DETM. Exxon Mobil does not have a similar right under the joint venture
agreements and once Duke Energy exercises the buy-out right, each party has the
right to "unwind" the buy-out under certain specific circumstances. In December
2000, Duke Energy exercised its right to buy the Exxon Mobil entities' interest
in the Ventures. Duke Energy claimed that refusal by the Exxon Mobil entities to
honor the exercise was a breach of the buy-out right provision, and sought
specific performance of the provision. Duke Energy also made additional claims
against the Exxon Mobil entities for breach of the agreements governing the
Ventures. Exxon Mobil also asserted breach of contract claims against Duke
Energy.
In December 2002, an arbitration panel issued a binding ruling against Exxon
Mobil on its claims against Duke Energy and granted Duke Energy favorable
declaratory relief. Duke Energy has terminated the previously exercised buy-out
provision.
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Trading Matters. Since April 2002, 17 shareholder class action lawsuits have
been filed against Duke Energy: 13 in the United States District Court for the
Southern District of New York and four in the United States District Court for
the Western District of North Carolina. The 13 lawsuits pending in New York were
consolidated into one action and included as co-defendants Duke Energy
executives and two investment banking firms. In December 2002, the New York
court granted in all respects the defendants' motion to dismiss the plaintiffs'
claims. The four lawsuits pending in North Carolina name as co-defendants Duke
Energy executives. Two of the four North Carolina suits have been consolidated
and involve claims under the Employee Retirement Income and Security Act
relating to the Company's Retirement Savings Plan. This consolidated action
names Duke Energy board members as co-defendants. In addition, Duke Energy has
received three shareholder's derivative notices demanding that it commence
litigation against named executives and directors of Duke Energy for alleged
breaches of fiduciary duties and insider trading. Duke Energy's response to the
derivative demands is not required until 90 days after receipt of written notice
requesting a response.
The class action lawsuits and the threatened shareholder derivative claims arise
out of allegations that Duke Energy improperly engaged in so-called "round-trip"
trades which resulted in an alleged overstatement of revenues over a three-year
period of approximately $1 billion. The plaintiffs seek recovery of an unstated
amount of compensatory damages, attorneys' fees and costs for alleged violations
of securities laws. In one of the lawsuits, the plaintiffs assert a common law
fraud claim and seek, in addition to compensatory damages, disgorgement and
punitive damages. Duke Energy intends to vigorously defend itself and its named
executives and board members.
In 2002, Duke Energy responded to information requests and subpoenas from the
FERC, the SEC, and the Commodity Futures Trading Commission (CFTC), and to grand
jury subpoenas issued by the U.S. Attorney's office in Houston, Texas. All
information requests and subpoenas seek documents and information related to
trading activities, including so-called "round-trip" trading. Duke Energy
received notice in mid-October that the SEC formalized its investigation
regarding "round-trip" trading. Duke Energy is cooperating with the respective
governmental agencies.
Duke Energy submitted a final report to the SEC based on a review of
approximately 750,000 trades made by various Duke Energy subsidiaries between
January 1, 1999 and June 30, 2002. Outside counsel conducted an extensive review
of trading, accounting, and other records, with the assistance of Duke Energy
senior legal, corporate risk management and accounting personnel. Duke Energy
identified 28 "round-trip" transactions done for the apparent purpose of
increasing volumes on the Intercontinental Exchange and 61 "round-trip"
transactions done at the direction of one of Duke Energy's traders that did not
have a legitimate business purpose and were contrary to corporate policy.
As a result of the trading review, Duke Energy has taken appropriate
disciplinary action and put in place additional risk management procedures to
improve and strengthen the oversight and controls of its trading operations.
Duke Energy has also reconfirmed to employees that engaging in simultaneous or
prearranged transactions that lack a legitimate business purpose, or any trading
activities that lack a legitimate business purpose, is against company policy.
As a result of Duke Energy's findings in the course of its investigation related
to the SEC inquiry on "round trip" trades, DENA identified accounting issues
that justified adjustments which reduced its EBIT by $11 million during 2002. An
additional $2 million charge was recorded in other Duke Energy business segments
related to these findings. Duke Energy completed its analysis of such round trip
trades in 2002.
On October 25, 2002, the FERC issued a data request to the "Largest North
American Gas Marketers, As Measured by 2001 Physical Sales Volumes (Bcf/d),"
including DETM. In general, the data request asks for information concerning
natural gas price data that was submitted by the gas marketers to entities that
publish natural gas price indices. DETM responded to the FERC's data request and
also is responding to requests that the CFTC has made for similar information.
Sonatrach. Duke Energy LNG Sales, Inc. (Duke LNG) initiated arbitration
proceedings against Sonatrach, the Algerian state-owned energy company, alleging
that Sonatrach had breached its obligations by its failure to provide shipping
under certain LNG Purchase and Transportation Agreements (the Sonatrach
Agreements) relating to Duke LNG's purchase of liquefied natural gas (LNG) from
Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. In
response to Duke LNG's claims, Sonatrach, together with its LNG sales and
marketing subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), have claimed
that Duke LNG repudiated the Sonatrach Agreements as a result of, among other
things, Duke LNG's alleged failure to diligently seek commitments from
customers, and to submit offers to Sonatrading based on such commitments, for
the purchase of LNG from Sonatrading. By virtue of Duke LNG's alleged breaches,
Sonatrach and Sonatrading seek to terminate the Sonatrach Agreements and to
recover damages from Duke LNG. Breifing and oral argument on this phase will be
completed in March 2003, and a ruling from the panel on issues of liability is
expected by late summer 2003. The damages phase for this proceeding will be
scheduled following the panel's liability ruling.
Enron Bankruptcy. On December 2, 2001, Enron Corporation and certain of its
affiliates filed for relief pursuant to Chapter 11 of the United States
Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New
York. Additional affiliates have filed for bankruptcy since that date. Certain
affiliates of Duke Energy engaged in transactions with various Enron entities
prior to the bankruptcy
40
filings. DETM was a member of the Official Committee of Unsecured Creditors in
the bankruptcy cases which are being jointly administered, but as of February
2003, DETM resigned from the official Committee of Unsecured Creditors in the
Enron bankruptcy case. Duke Energy has taken a reserve to offset its exposure to
Enron.
In mid-November 2002, various Enron trading entities demanded payment from DETM
and Duke Energy Merchants, L.L.C. (DEM) for certain energy commodity sales
transactions without regard to the set off rights of DETM and DEM and demanded
that DETM detail balances due under certain master trading agreements without
regard to the set-off rights of DETM. On December 13, 2002, DETM and DEM filed
an adversary proceeding against Enron Corporation and certain of its affiliates
(collectively Enron), seeking, among other things, a declaration affirming each
plaintiff's right to set off its respective debts to Enron. The complaint
alleges that the Enron affiliates were operated by Enron Corporation as its
alter ego and as components of a single trading enterprise and that DETM and DEM
should be permitted to exercise their respective rights of mutual set-off
against the Enron trading enterprise under the Bankruptcy Code. The complaint
also seeks the imposition of a constructive trust so that any claims by Enron
against DETM or DEM are subject to the respective set off rights of DETM and
DEM. Enron's has filed its response asserting that DETM and DEM are not entitled
to the requested relief.
Duke Energy and its subsidiaries are involved in other legal, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding performance, contracts, royalty disputes, mismeasurement and
mispayment claims (some of which are brought as class actions), and other
matters arising in the ordinary course of business, some of which involve
substantial amounts. Management believes that the final disposition of these
proceedings will have no material adverse effect on consolidated results of
operations, cash flows or financial position.
Impairment Charges and Other Matters
In response to the downturn in the energy merchant sector, and overall sluggish
economy in 2002, Duke Energy has taken steps to cut costs and downsize our
business. Duke Energy recorded asset impairment charges in 2002 of almost $500
million in our energy services businesses due to our revised outlook of the
markets and Duke Energy's decision to abandon certain projects and suspend
others. These charges included goodwill impairment, site development cost
write-offs, technology system write-off, plant impairment and turbine write-offs
and were calculated applying generally accepted accounting principles, primarily
SFAS 142 and SFAS 144.
During 2002, Field Services also recorded, as part of its internal review of
balance sheet accounts, approximately $52 million of charges in the following
five categories: operating expense accruals; gas inventory adjustments; gas
imbalances; joint venture and investment account reconciliation; and other
balance sheet accounts. Approximately $37 million of these charges are
corrections of errors from prior years which are immaterial to Duke Energy's
reported results. This review of balance sheet accounts is complete.
Additionally, Field Services recorded impairment charges of $28 million for
certain operating assets in accordance with SFAS 144.
During 2002, Duke Energy reduced its workforce to align the business with
current market conditions. Duke Energy recorded charges totaling approximately
$100 million related to these reductions. The charges were recorded consistent
with applicable accounting rules including EITF 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(Including Certain Cost Incurred in a Restructuring)" and SFAS No. 112,
"Employers' Accounting for Postemployment Benefits - An Amendment of FASB
Statements No. 5 and 43)."
41
Forward-Looking Statements. Duke Energy's reports, filings and other public
announcements may include statements that reflect assumptions, projections,
expectations, intentions or beliefs about future events. These statements are
intended as "forward-looking statements" under the Private Securities Litigation
Reform Act of 1995. Generally, the words "may," "could," "project," "believe,"
"anticipate," "expect," "estimate," "plan," "forecast," "intend" and similar
words identify forward-looking statements, which generally are not historical in
nature. All such statements (other than statements of historical facts),
including statements regarding operating performance, financial position,
business strategy, budgets, projected costs, plans and objectives of management
for future operations and events or developments that we expect or anticipate
will occur in the future, are forward looking. Forward-looking statements are
subject to certain risks and uncertainties that could, and often do, cause
actual results to differ from Duke Energy's historical experience and our
present expectations or projections. Accordingly, there can be no assurance that
actual results will not differ materially from those expressed or implied by the
forward-looking statements. Caution should be taken not to place undue reliance
on any such forward-looking statements.
Factors that could cause actual results to differ materially from the
expectations expressed or implied in such forward-looking statements include,
but are not limited to: state, federal and foreign legislative and regulatory
initiatives that affect cost and investment recovery, have an impact on rate
structures and affect the speed and degree at which competition enters the
electric and natural gas industries; industrial, commercial and residential
growth in the service territories of Duke Energy and its subsidiaries; the
weather and other natural phenomena; the timing and extent of changes in
commodity prices, interest rates and foreign currency exchange rates; changes in
environmental and other laws and regulations to which Duke Energy and its
subsidiaries are subject or other external factors over which Duke Energy has no
control; the results of financing efforts, including Duke Energy's ability to
obtain financing on favorable terms, which can be affected by Duke Energy's
credit rating and general economic conditions; level of creditworthiness of
counterparties to transactions; growth opportunities for Duke Energy's business
units; and the effect of accounting policies issued periodically by accounting
standard-setting bodies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See "Management's Discussion and Analysis of Results of Operations and Financial
Condition, Quantitative and Qualitative Disclosures About Market Risk."
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