EXHIBIT 99(B)
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Introduction
Management's Discussion and Analysis should be read in conjunction with the
Consolidated Financial Statements.
Business Segments. Duke Energy Corporation (collectively with its
subsidiaries, "Duke Energy") is an integrated energy and energy services
provider with the ability to offer 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 electric
energy in central and western North Carolina and the western portion of South
Carolina. Its operations are conducted 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 interstate transportation and storage of
natural gas for customers primarily in the Mid-Atlantic, New England and
southeastern states. Its operations are conducted primarily through Duke Energy
Gas Transmission Corporation. The interstate natural gas transmission and
storage operations are subject to the rules and regulations of the FERC.
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores natural gas liquids (NGLs).
Its operations are conducted primarily through Duke Energy Field Services, LLC
(DEFS), a limited liability company that is approximately 30% owned by Phillips
Petroleum. Field Services operates gathering systems in western Canada and 11
contiguous states that serve major natural gas-producing regions in the Rocky
Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-North
Louisiana, as well as onshore and offshore Gulf Coast areas.
North American Wholesale Energy's (NAWE's) activities include asset
development, operation and management, primarily through Duke Energy North
America, LLC (DENA), and commodity sales and services related to natural gas
and power, primarily through Duke Energy Trading and Marketing, LLC (DETM).
DETM is a limited liability company that is approximately 40% owned by Exxon
Mobil Corporation. NAWE also includes Duke Energy Merchants, which develops new
business lines in the evolving energy commodity markets. NAWE conducts its
business throughout the U.S. and Canada. The operations of the previously
segregated Trading and Marketing segment were combined by management into NAWE
during 2000. Previous periods have been restated to conform to current period
presentation.
International Energy conducts its operations through Duke Energy
International, LLC. International Energy's activities include asset
development, operation and management of natural gas and power facilities and
energy trading and marketing of natural gas and electric power. This activity
is targeted in 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). D/FD is a
50/50 partnership between Duke Energy and Fluor Enterprises, Inc.
Duke Ventures is comprised of other diverse businesses, primarily operating
through Crescent Resources, Inc. (Crescent), DukeNet Communications, LLC
(DukeNet) and Duke Capital Partners (DCP). Crescent develops high-quality
commercial, residential and multi-family real estate projects and manages land
holdings
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primarily in the southeastern U.S. DukeNet provides fiber optic networks for
industrial, commercial and residential customers. DCP, a newly formed, wholly
owned merchant finance company, provides financing, investment banking and
asset management services to wholesale and commercial energy markets.
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 electric power, 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 comprehensive capabilities. Domestically, Duke Energy is
aggressively investing in new merchant power plants throughout the U.S.,
expanding its natural gas pipeline infrastructure in the eastern U.S., rapidly
increasing 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. Internationally, Duke Energy is currently
focusing on integrated electric and natural gas opportunities in Latin America,
Asia Pacific and Europe.
Franchised Electric continues to add customers, maintain low costs and
deliver high-quality customer service. Franchised Electric is expected to grow
moderately, consistent with historical trends. Expansion will primarily result
from continued economic growth in its service territory.
Natural Gas Transmission has increased 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 market-leading size, scope and reliability of
supply in natural gas gathering, 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.
NAWE 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. To capture the greatest value in the
U.S., DENA, through its portfolio management strategy, seeks opportunities to
invest in energy assets in 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 NAWE
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 plans to grow by providing an expanding customer base
with a variety of engineering and energy efficiency services that allow
customers to more effectively deal with rapidly changing conditions in the
energy marketplace.
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 can 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 industry restructuring in North
Carolina and South Carolina.
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Results of Operations
In 2000, earnings available for common stockholders were $1,757 million, or
$2.39 per basic share, including a pre-tax gain of $407 million, or an after-
tax gain of $0.34 per basic share, on the sale of Duke Energy's 20% interest in
BellSouth Carolina PCS (BellSouth PCS). In 1999, earnings available for common
stockholders were $1,487 million, or $2.04 per basic share, including an after-
tax extraordinary gain of $660 million, or $0.91 per basic share resulting from
the sale of the Panhandle Eastern Pipe Line Company (PEPL), Trunkline Gas
Company (Trunkline) and additional storage related to those systems, which
substantially comprised the Midwest Pipelines along with Trunkline LNG Company.
The increase in earnings available for common stockholders in 2000 was
primarily due to a 96% increase in segment earnings as described below,
including the BellSouth PCS gain. Partially offsetting this increase was the
1999 extraordinary gain and higher interest and minority interest expense in
the current year.
Earnings available for common stockholders increased $256 million in 1999
from 1998 earnings of $1,231 million, or $1.70 per basic share. The increase in
earnings available for common stockholders was primarily due to the 1999
extraordinary gain resulting from the sale of the Midwest Pipelines. This gain,
along with the factors described below that affect segment earnings, was
partially offset by a pre-tax $800 million charge for estimated injury and
damages claims (see Note 14 to the Consolidated Financial Statements) and
higher interest and minority interest expense.
Earnings per share information provided above has been restated to reflect
the two-for-one common stock split effective January 26, 2001. See Note 15 to
the Consolidated Financial Statements for additional information.
Operating income for 2000 was $3,813 million compared to $1,819 million in
1999 and $2,485 million in 1998. Earnings before interest and taxes (EBIT) were
$4,014 million, $2,043 million and $2,647 million for 2000, 1999 and 1998,
respectively. Management evaluates each business segment based on an internal
measure of EBIT, after deducting minority interests. Operating income and EBIT
are affected by the same fluctuations for Duke Energy and each of its business
segments. The only notable difference between operating income and EBIT is the
inclusion in EBIT of certain non-operating activities. See Note 3 to the
Consolidated Financial Statements for additional information on business
segments. EBIT is summarized in the following table and is discussed by
business segment thereafter.
EBIT by Business Segment
Years Ended December
31,
----------------------
2000 1999 1998
------ ------ ------
(in millions)
Franchised Electric..................................... $1,704 $ 856 $1,513
Natural Gas Transmission................................ 534 627 702
Field Services.......................................... 296 144 76
North American Wholesale Energy......................... 418 209 133
International Energy.................................... 331 42 12
Other Energy Services................................... (61) (94) 10
Duke Ventures........................................... 563 162 122
Other Operations........................................ (2) 5 22
EBIT attributable to minority interests................. 231 92 57
------ ------ ------
Consolidated EBIT....................................... $4,014 $2,043 $2,647
====== ====== ======
Other Operations primarily include certain unallocated corporate costs.
Included in the amounts discussed hereafter are intercompany transactions that
are eliminated in the Consolidated Financial Statements.
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Franchised Electric
Years Ended December
31,
--------------------
2000 1999 1998
------ ------ ------
(In millions, except
where noted)
Operating revenues........................................ $4,946 $4,700 $4,626
Operating expenses........................................ 3,316 3,966 3,228
------ ------ ------
Operating income.......................................... 1,630 734 1,398
Other income, net of expenses............................. 74 122 115
------ ------ ------
EBIT...................................................... $1,704 $ 856 $1,513
====== ====== ======
Sales--GWh(a)............................................. 84,766 81,548 82,011
- --------
(a) Gigawatt-hours.
Franchised Electric's EBIT increased $848 million in 2000 when compared to
1999, primarily due to an $800 million charge in 1999 for estimated injury and
damages claims (see Note 14 to the Consolidated Financial Statements). Overall
favorable weather and growth in customers, partially offset by increased
operating costs, also contributed to this increase in EBIT. The average number
of customers in Franchised Electric's service territory increased 2.5% during
2000. Total gigawatt-hour sales to customers increased by 3.9% for 2000. Sales
to general service and residential customers increased 4.7% and 4.4%,
respectively, while total industrial sales decreased 0.5%.
In 1999, Franchised Electric's EBIT decreased $657 million compared to 1998,
primarily due to the above-mentioned charge for estimated injury and damages
claims. Partially offsetting this decrease was a 2.8% increase in the number of
customers in Franchised Electric's service territory during 1999, and the
absence of 1998 severance and other costs related to closing Franchised
Electric's merchandising business.
Natural Gas Transmission
Years Ended December
31,
--------------------
2000 1999 1998
------ ------ ------
(In millions, except
where noted)
Operating revenues........................................ $1,131 $1,230 $1,542
Operating expenses........................................ 609 615 864
------ ------ ------
Operating income.......................................... 522 615 678
Other income, net of expenses............................. 12 12 24
------ ------ ------
EBIT...................................................... $ 534 $ 627 $ 702
====== ====== ======
Throughput--TBtu(a)....................................... 1,717 1,893 2,593
- --------
(a) Trillion British thermal units.
In 2000, EBIT for Natural Gas Transmission decreased $93 million compared to
1999, primarily due to $132 million of EBIT in 1999 that did not reoccur in
2000. These items consisted of $70 million of EBIT related to the Midwest
Pipelines, which were sold to CMS Energy Corporation (CMS) in March 1999; a $24
million gain resulting from the sale of Duke Energy's interest in the Alliance
Pipeline project; and benefits totaling $38 million related to the completion
of certain environmental cleanup programs below estimates. These items were
partially offset by increased earnings from market-expansion projects and joint
ventures such as the Maritimes & Northeast Pipeline, which was placed into
service in December 1999, and earnings from East Tennessee Natural Gas Company
and Market Hub Partners (MHP), which were acquired in March and September 2000,
respectively. See Note 2 to the Consolidated Financial Statements for
additional information on the sale of the Midwest Pipelines and the
acquisitions of East Tennessee Natural Gas Company and MHP.
S-4
EBIT for Natural Gas Transmission decreased $75 million in 1999 compared to
1998. As a result of the sale of the Midwest Pipelines in March 1999, EBIT for
the Midwest Pipelines decreased $156 million compared to 1998's full year of
operation. For the remainder of Natural Gas Transmission, EBIT increased $81
million compared to 1998, primarily as a result of increased earnings from
market-expansion projects and joint ventures, higher throughput and lower
operating expenses. A $24 million gain resulting from the sale of Duke Energy's
interest in the Alliance Pipeline project and benefits totaling $38 million
related to the completion of certain environmental cleanup programs below
estimates also increased EBIT in 1999. Partially offsetting these contributions
to EBIT were the favorable impacts in 1998 in connection with the resolution of
regulatory issues related to natural gas supply realignment costs and a refund
from a state property tax ruling.
Field Services
Years Ended December
31,
---------------------
2000 1999 1998
------ ------ ------
(In millions, except
where noted)
Operating revenues..................................... $9,060 $3,590 $2,677
Operating expenses..................................... 8,635 3,444 2,598
------ ------ ------
Operating income....................................... 425 146 79
Other income, net of expenses.......................... 6 (2) (3)
Minority interest expense.............................. 135 -- --
------ ------ ------
EBIT................................................... $ 296 $ 144 $ 76
====== ====== ======
Natural gas gathered and processed/transported,
TBtu/d(a)............................................. 7.6 5.1 3.6
NGL production, MBbl/d(b).............................. 358.5 192.4 110.2
Natural gas marketed, TBtu/d........................... 0.7 0.5 0.4
Average natural gas price per MMBtu(c)................. $ 3.89 $ 2.27 $ 2.11
Average NGL price per gallon(d)........................ $ 0.53 $ 0.34 $ 0.26
- --------
(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 $152 million in 2000 from 1999. The increase
in EBIT and volume activity was primarily due to the combination of Field
Services' natural gas gathering, processing and marketing business with
Phillips Petroleum's Gas Gathering, Processing and Marketing unit (Phillips) in
March 2000; the acquisition of the natural gas gathering, processing,
fractionation and NGL pipeline business from Union Pacific Resources (UPR)
(collectively, the "UPR acquisition") in April 1999; and other recent
acquisitions and plant expansions. For additional information on the Phillips
combination and the UPR acquisition, see Note 2 to the Consolidated Financial
Statements. Improved average NGL prices, which increased 56% over 1999 prices,
also contributed significantly to the increase in EBIT.
In 1999, Field Services' EBIT increased $68 million compared to 1998. A
significant portion of the increase resulted from earnings from the UPR
acquisition. Improved average NGL prices, which were up 31% from the prior
year, also contributed to the increase in EBIT. Partially offsetting these
increases were $34 million of asset sale gains in 1998.
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North American Wholesale Energy
Years Ended December
31,
----------------------
2000 1999 1998
------- ------- ------
(In millions, except
where noted)
Operating revenues...................................... $33,874 $11,801 $8,783
Operating expenses...................................... 33,386 11,591 8,619
------- ------- ------
Operating income........................................ 488 210 164
Other income, net of expenses........................... 3 60 20
Minority interest expense............................... 73 61 51
------- ------- ------
EBIT.................................................... $ 418 $ 209 $ 133
======= ======= ======
Natural gas marketed, TBtu/d............................ 11.9 10.5 8.0
Electricity marketed, GWh............................... 275,258 109,634 98,991
Proportional megawatt capacity owned(a)................. 8,984 5,799 5,098
- --------
(a) Includes under construction or under contract.
NAWE's EBIT increased $209 million in 2000 compared to 1999. The increase
was 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 as a
result of NAWE executing its portfolio management strategy. Operating revenues
and expenses increased as the volumes of natural gas and power marketed
increased 13% and 151%, respectively. These increases were partially offset by
a $110 million charge related to receivables for energy sales in California,
and increased operating and development costs associated with business
expansion. See the Current Issues, California Issues section of Management's
Discussion and Analysis, and Note 14 to the Consolidated Financial Statements
for further information.
In 1999, EBIT for NAWE increased $76 million from 1998. The increase
included $99 million in income from the sale of partial interests in four
generating facilities as a result of NAWE executing its portfolio management
strategy. Partially offsetting these increases were lower natural gas trading
margins, partially offset by higher power trading margins as well as margins
associated with other trading activities and sales of natural gas interests
associated with drilling activities. Higher operating expenses and increased
development costs associated with business expansion also partially offset the
earnings increases.
International Energy
Years Ended December 31,
---------------------------
2000 1999 1998
--------- -------- --------
(In millions, except
where noted)
Operating revenues................................. $ 1,067 $ 357 $ 159
Operating expenses................................. 755 292 145
--------- -------- -------
Operating income................................... 312 65 14
Other income, net of expenses...................... 42 8 4
Minority interest expense.......................... 23 31 6
--------- -------- -------
EBIT............................................... $ 331 $ 42 $ 12
========= ======== =======
Proportional megawatt capacity owned(a)............ 4,876 2,974 943
Proportional maximum pipeline capacity(a),
MMcf/d(b)......................................... 416 321 124
- --------
(a) Includes under construction or under contract.
(b) Million cubic feet per day.
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International Energy's EBIT increased $289 million in 2000 when 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 certain
assets relating to the transportation of liquefied natural gas.
In 1999, International Energy's EBIT increased $30 million compared to 1998.
Earnings from new investments in Latin America and Australia contributed $63
million to the increase. Partially offsetting these increases were higher
operating expenses and increased development costs associated with business
expansion.
Other Energy Services
Years Ended December 31,
----------------------------
2000 1999 1998
-------- --------- --------
(In millions)
Operating revenues............................... $ 695 $ 989 $ 521
Operating expenses............................... 756 1,083 511
------- --------- -------
EBIT............................................. $ (61) $ (94) $ 10
======= ========= =======
In 2000, EBIT for Other Energy Services improved $33 million compared to
1999. New business activity and decreased operating expenses at DukeSolutions,
and earnings related to new projects at D/FD were responsible for current year
improved EBIT. The results for 2000 also include Duke Energy's portion of an
estimated project loss recorded by D/FD of approximately $62 million, partially
offset by 1999 charges of $38 million and $35 million at DE&S and
DukeSolutions, respectively. The 1999 charges primarily related to expenses for
severance and office closings associated with repositioning the companies for
growth.
EBIT for Other Energy Services decreased $104 million in 1999 compared to
1998. The decrease was primarily due to the above-mentioned charges of $38
million and $35 million at DE&S and DukeSolutions, respectively. Increased
development costs at DukeSolutions and decreased earnings from projects of DE&S
also contributed to lower EBIT.
Duke Ventures
Years Ended December 31,
--------------------------
2000 1999 1998
-------- -------- --------
(In millions)
Operating revenues................................ $ 642 $ 232 $ 171
Operating expenses................................ 79 70 49
-------- -------- --------
EBIT.............................................. $ 563 $ 162 $ 122
======== ======== ========
EBIT for Duke Ventures increased $401 million in 2000 when compared to 1999.
This increase is primarily attributable to the sale by DukeNet of its 20%
interest in BellSouth PCS to BellSouth Corporation for a pre-tax gain of $407
million. Slightly offsetting this increase in EBIT was a decrease in commercial
project sales and land sales at Crescent.
In 1999, EBIT for Duke Ventures increased $40 million compared to 1998. The
increase was primarily due to Crescent's increased residential developed lot
sales, land sales and commercial project sales, partially offset by decreased
lake lot sales. Increased fiber optic revenues at DukeNet and decreased losses
related to its interest in BellSouth PCS also contributed to increased EBIT.
S-7
Other Impacts on Earnings Available for Common Stockholders
Interest expense increased $310 million in 2000 compared to 1999, and $87
million in 1999 compared to 1998 due to higher average debt balances
outstanding, resulting from acquisitions and expansion.
Minority interest expense increased $165 million in 2000 compared to 1999
and $46 million in 1999 compared to 1998. Included in minority interest expense
is expense related to regular distributions on issuances of Duke Energy's trust
preferred securities (see Note 12 to the Consolidated Financial Statements).
This expense increased $21 million for 2000 and $43 million for 1999 due to
additional issuances of Duke Energy's trust preferred securities during 1999
and 1998.
In addition, the increase for 2000 includes minority interest expense
related to Field Services' combination with Phillips Petroleum, and increased
minority interest expense at NAWE related to its joint venture with Exxon Mobil
Corporation, partially offset by decreased minority interest expense at
International Energy related to its 1999 and 2000 acquisitions. The 1999
increase in minority interest expense over 1998 related primarily to
International Energy's 1999 investments and NAWE's joint venture with Exxon
Mobil Corporation. For additional information regarding acquisitions and new
joint venture projects, see Notes 2 and 8 to the Consolidated Financial
Statements.
Duke Energy's effective income tax rate was approximately 37%, 35% and 38%
for 2000, 1999 and 1998, respectively. The decrease in 1999 was primarily due
to the favorable resolution of several income tax issues and the utilization of
certain capital loss carryforwards due to the sale of the Midwest Pipelines.
The sale of the Midwest Pipelines to CMS closed in March 1999 and resulted
in a $660 million extraordinary gain, net of income tax of $404 million (see
Note 2 to the Consolidated Financial Statements).
In January 1998, TEPPCO Partners, LP, in which Duke Energy has a 21.1%
ownership interest, redeemed certain First Mortgage Notes. This resulted in a
non-cash extraordinary loss of $8 million, net of income tax of $5 million,
related to Duke Energy's share of costs of the early retirement of debt.
Liquidity and Capital Resources
Operating Cash Flows
Net cash provided by operations was $2,225 million in 2000, $2,684 million
in 1999 and $2,331 million in 1998. Cash flows from operations decreased in
2000 compared to 1999 primarily due to tax payments made in 2000 related to the
sale of the Midwest Pipelines. The increase in cash flows from operations in
1999 from 1998 was primarily due to net income resulting from business
expansion.
In 1999, Duke Energy established an accrual for estimated injury and damages
claims. During 2000, Duke Energy paid approximately $253 million for the
related insurance premium. Management believes that the long-term cash
requirements of the projected liability will not have a material effect on Duke
Energy's liquidity or cash flows. See Note 14 to the Consolidated Financial
Statements for further discussion.
Investing Cash Flows
Capital and investment expenditures were approximately $5.6 billion in 2000
compared to $5.9 billion in 1999. The primary use of cash in investing
activities for capital and investment expenditures reflects development and
expansion expenditures, upgrades to existing assets and the acquisitions of
various businesses and assets. The change in Natural Gas Transmission's capital
expenditures is primarily due to business expansion related to the
approximately $390 million acquisition of East Tennessee Natural Gas Company
and the approximately $250 million of cash for the acquisition of MHP. In 2000,
NAWE began construction of a number of power generation plants in the U.S. and
continued capital expenditures on projects initiated prior to 2000.
International Energy's business expansion included the completion of a tender
offer to the minority
S-8
shareholders of Companhia de Geracao de Energia Eletrica Paranapanema
(Paranapanema) for approximately $280 million and the completion of 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 2000 sale of Duke Energy's 20% interest in BellSouth
PCS to BellSouth Corporation. For additional information concerning significant
acquisitions and dispositions, see Note 2 to the Consolidated Financial
Statements.
Capital and Investment Expenditures by Business Segment
Years Ended December
31,
--------------------
2000 1999 1998
------ ------ ------
(in millions)
Franchised Electric....................................... $ 661 $ 759 $ 586
Natural Gas Transmission.................................. 973 261 290
Field Services............................................ 376 1,630 304
North American Wholesale Energy........................... 1,937 1,028 796
International Energy...................................... 980 1,779 239
Other Energy Services..................................... 28 94 41
Duke Ventures............................................. 643 382 232
Other Operations.......................................... 36 3 12
------ ------ ------
Total consolidated...................................... $5,634 $5,936 $2,500
====== ====== ======
Capital and investment expenditures in 1999 increased approximately $3.4
billion from 1998 capital and investment expenditures of approximately $2.5
billion. The increase primarily resulted from business expansion for the Field
Services, NAWE and International Energy business segments. Business expansion
for Field Services included the $1.35 billion UPR acquisition. In 1999, NAWE
began construction of multiple power generation plants in the U.S. and
continued capital expenditures on projects initiated prior to 1999.
International Energy's business expansion included $1.7 billion for multiple
acquisitions in Latin America, western Australia and New Zealand. Expenditures
related to these activities were partially funded by $1.9 billion in cash
proceeds from the sale of the Midwest Pipelines. For additional information
concerning significant acquisitions and dispositions, see Note 2 to the
Consolidated Financial Statements.
Projected 2001 capital and investment expenditures for Duke Energy are
approximately $7.9 billion, of which over 75% is planned to be for competitive
business segments which are not subject to state rate regulation. This
projection includes approximately $6.5 billion for acquisitions and other
expansion opportunities and $1.4 billion for existing plant upgrades. Duke
Energy's projected capital expenditures also include $800 million in
expenditures over the next three years for its Gulfstream pipeline project.
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.
Financing Cash Flows
Duke Energy's consolidated capital structure at December 31, 2000, including
short-term debt, was 48% debt, 46% common equity and minority interests, 5%
trust preferred securities and 1% preferred stock. Fixed charges coverage,
calculated using the Securities and Exchange Commission (SEC) method, was 3.8
times, 2.9 times and 4.7 times for 2000, 1999 and 1998, respectively.
Duke Energy's business expansion opportunities, along with dividends, debt
repayments and operating requirements, are expected to be funded by cash from
operations, external financing, common stock issuances and the proceeds from
certain asset sales. Funding requirements met by external financing, common
stock
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issuances and proceeds from the sale of assets are dependent upon the
opportunities presented and favorable market conditions. Management believes
Duke Energy has adequate financial resources to meet its future needs.
During 2000, Duke Energy issued a total of $550 million of Senior Notes at
rates of approximately 7.250%. The proceeds were used for general corporate
purposes. In April 2000, DEFS issued approximately $2.75 billion of commercial
paper associated with the Phillips combination of which $1.22 billion was
distributed to Phillips Petroleum. In August 2000, DEFS issued $1.7 billion of
notes at rates from 7.50% to 8.125% and reduced the outstanding balance of its
commercial paper. In December 2000, Texas Eastern Transmission Corporation
(TETCO) issued $300 million of 7.30% notes due 2010. For additional information
regarding debt, see Note 10 to the Consolidated Financial Statements.
During 2000, Duke Energy formed Catawba River Associates, LLC, and third-
party, non-controlling, preferred interest holders invested approximately
$1,025 million. The preferred interest receives a preferred return equal to an
adjusted floating reference rate (approximately 7.847% at December 31, 2000).
See Note 2 to the Consolidated Financial Statements for further discussion.
During 2000, Duke Energy repaid $380 million of 8.0% notes, $200 million of
7.0% notes, $200 million of 10.375% notes and made $323 million in scheduled
debt repayments. In addition, Duke Energy made a tender offer for $115 million
of the notes assumed with the acquisition of MHP. As of December 31, 2000,
approximately $88 million of these notes had been retired.
Under its commercial paper facilities and extendible commercial note
programs (ECNs), Duke Energy had the ability to borrow up to $5.7 billion and
$3.3 billion at December 31, 2000 and 1999, respectively. A summary of the
available commercial paper and ECNs as of December 31, 2000, is as follows:
Duke Energy
Duke Duke Capital Field Duke Energy
Energy Corporation(a) Services International Total
------ -------------- ----------- ------------- -----
(in billions)
Commercial paper......... $1.25 $1.55 $1.00(b) $0.41(c) $4.21
ECNs..................... 0.50 1.00 -- -- 1.50
----- ----- ----- ----- -----
Total.................. $1.75 $2.55 $1.00 $0.41 $5.71
===== ===== ===== ===== =====
- --------
(a) Duke Capital Corporation is a wholly owned subsidiary of Duke Energy that
provides financing and credit enhancement services for its subsidiaries.
(b) Original availability of $2.8 billion was reduced to $1.0 billion upon
DEFS' issuance of $1.7 billion in notes in August 2000.
(c) Includes ability to issue medium-term notes.
The amount of Duke Energy's bank credit and construction facilities
available at December 31, 2000 and 1999, was approximately $4.2 billion and
$3.7 billion, respectively. Certain of the bank credit facilities support the
issuance of commercial paper; therefore, the issuance of commercial paper
reduces the amount available under these credit facilities. At December 31,
2000, approximately $3.2 billion was outstanding under the commercial paper
facilities and ECNs, and approximately $44 million was outstanding under bank
credit and construction facilities.
As of December 31, 2000, Duke Energy and its subsidiaries had the ability to
issue up to $4.5 billion aggregate public offering price of debt and other
securities under shelf registrations filed with the SEC. 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.
On December 20, 2000, Duke Energy announced a two-for-one common stock split
effective January 26, 2001, to shareholders of record on January 3, 2001. All
outstanding share and per-share amounts have been restated to reflect the stock
split.
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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 December 2000 that maintains dividends at the current quarterly rate
of $0.275 per share, subject to declarations from time to time 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 74 consecutive years. Dividends on common and
preferred stocks in 2001 are expected to be paid on March 16, June 18,
September 17 and December 17, 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 2000, 1999 or 1998.
Duke Energy used authorized but unissued shares of its common stock to meet
2000 and 1999 employee benefit plan contribution requirements. This practice is
expected to continue in 2001.
Quantitative and Qualitative Disclosures About Market Risk
Risk Policies
Duke Energy is exposed to market risks associated with interest rates,
commodity prices, equity prices and foreign currency exchange rates.
Comprehensive risk management policies have been established by management 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
comprised of senior executives who receive periodic updates from the Chief Risk
Officer (CRO) on market risk positions, corporate exposures, credit exposures
and overall results of Duke Energy's risk management activities. The CRO has
responsibility for the overall management of interest rate risk, foreign
currency risk, credit risk and energy risk, including monitoring of exposure
limits.
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-rate securities, commercial
paper and auction market preferred stock, as well as interest rate swaps and
interest rate lock agreements. 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 may also enter into financial
derivative instruments, including, but not limited to, swaps, options and
treasury lock agreements to manage and mitigate interest rate risk exposure.
See Notes 1, 7, 10, 12 and 13 to the Consolidated Financial Statements for
additional information.
Based on a sensitivity analysis as of December 31, 2000, it was estimated
that if market interest rates average 1% higher (lower) in 2001 than in 2000,
earnings before income taxes would decrease (increase) by approximately $53
million. Comparatively, based on a sensitivity analysis as of December 31,
1999, had interest rates averaged 1% higher (lower) in 2000 than in 1999, it
was estimated that earnings before income taxes would have decreased
(increased) by approximately $24 million. These amounts were determined by
considering the impact of the hypothetical interest rates on the variable-rate
securities outstanding as of December 31, 2000 and 1999. The increase in
interest rate sensitivity is primarily the result of the increase in
outstanding variable-rate commercial paper. In the event of a significant
change in interest rates, 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.
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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. See Notes 1 and 7 to the Consolidated
Financial Statements for additional information.
The risk in the commodity trading portfolio is measured and monitored on a
daily basis utilizing a Value-at-Risk model to determine the maximum potential
one-day favorable or unfavorable Daily Earnings at Risk (DER). The DER is
monitored daily in comparison to established thresholds. Other measures are
also utilized to limit and monitor the risk in the commodity trading portfolio
on monthly and annual bases.
The DER computations are based on a historical simulation, which utilizes
price movements over a specified period to simulate forward price curves in the
energy markets to estimate the 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. The 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
calculation includes commodity derivative instruments held for trading
purposes. Duke Energy's DER amounts are depicted in the table below. The
increase in DER amounts as compared to 1999 is a result of Duke Energy's
expanding portfolio of energy-related products both domestically and
internationally.
Daily Earnings at Risk
Estimated One-Day Estimated One-Day Estimated Average Estimated Average
Operational Impact on EBIT at Impact on EBIT at One-Day Impact on One-Day Impact on
Locations December 31, 2000 December 31, 1999 EBIT for 2000 EBIT for 1999
----------- ----------------- ----------------- ----------------- -----------------
(in millions) (a)
North American.. $20 $10 $16 $11
Other
international.. 11 -- 2 --
- --------
(a) Changes in markets inconsistent with historical trends could cause actual
results to exceed predicted limits.
Certain subsidiaries of Duke Energy are also exposed to market fluctuations
in the prices of various commodities related to their ongoing power generating,
natural gas gathering, processing and marketing activities. Duke Energy closely
monitors the risks associated with these commodities' price changes on its
future operations, and where appropriate, uses various commodity instruments,
such as electricity, natural gas, crude oil and NGLs to hedge these price
risks. Based on a sensitivity analysis as of December 31, 2000, it was
estimated that if NGL prices average one cent per gallon less in 2001, EBIT
would decrease by approximately $8 million, after considering the effect of
Duke Energy's commodity hedge positions. Comparatively, the same sensitivity
analysis as of December 31, 1999, estimated that EBIT would have decreased by
approximately $6 million. 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, 2000 or 1999.
Credit Risk
Duke Energy's principal markets for power and natural gas marketing services
are industrial end-users and utilities located throughout the U.S., Canada,
Asia Pacific 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. On all transactions where Duke Energy is exposed to credit risk, Duke
Energy analyzes the counterparties' financial
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condition prior to entering into an agreement, establishes credit limits and
monitors the appropriateness of these limits on an ongoing basis. As of
December 31, 2000, Duke Energy had approximately $400 million in receivables
related to energy sales in California. Duke Energy quantified its exposures
with regard to those receivables and recorded a provision of $110 million. See
the Current Issues, California Issues section of Management's Discussion and
Analysis, and Note 14 to the Consolidated Financial Statements for further
information regarding credit exposure.
The change in market value of New York Mercantile Exchange-traded futures
and options contracts requires daily cash settlement in margin accounts with
brokers. Physical forward contracts and financial derivatives are generally
settled at the expiration of the contract term or each delivery period;
however, these transactions are also generally subject to margin agreements
with the majority of Duke Energy's counterparties.
Equity Price Risk
Duke Energy maintains trust funds, as required by the Nuclear Regulatory
Commission, to fund certain costs of nuclear decommissioning (see Note 11 to
the Consolidated Financial Statements). As of December 31, 2000 and 1999, these
funds were invested primarily in domestic and international equity securities,
fixed-rate, fixed-income securities and cash and cash equivalents. Management
believes that its exposure to fluctuations in equity prices or interest rates
will not materially affect consolidated results of operations, cash flows or
financial position. See further discussion in the Current Issues, Nuclear
Decommissioning Costs section of Management's Discussion and Analysis.
Foreign Currency Risk
Duke Energy is exposed to foreign currency risk that arises from investments
in international affiliates and businesses owned and operated in foreign
countries. To mitigate risks associated with foreign currency fluctuations,
when possible, contracts are denominated in or indexed to the U.S. dollar, or
investments may be hedged through debt denominated 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 a devaluation of the foreign currencies to which it has exposure.
At December 31, 2000, Duke Energy's primary foreign currency exchange 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, 2000, a 10%
devaluation in the currency exchange rates in Brazil would reduce Duke Energy's
financial position by approximately $91 million and would not significantly
affect Duke Energy's consolidated results of operations, cash flows or
financial position over the next 12 months. Based on a sensitivity analysis as
of December 31, 1999, a 10% devaluation in the Brazilian currency exchange
rates would have reduced Duke Energy's financial position by approximately $65
million. The increase in sensitivity to the Brazilian real is primarily due to
the increased investment in Paranapanema as a result of Duke Energy's tender
offer in 2000. See Note 2 to the Consolidated Financial Statements for further
information. Based on these sensitivity analyses, a 10% devaluation in other
foreign currencies was insignificant to Duke Energy's 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
final rules provides energy suppliers, including Duke Energy, with
opportunities to sell and deliver capacity and energy at market-based prices.
Franchised Electric obtained from the FERC's open-access rule the rights to
sell capacity and energy at
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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.
On December 20, 1999 and February 25, 2000, the FERC issued its Order 2000
and Order 2000-A regarding Regional Transmission Organizations (RTOs). In these
orders, the FERC stressed the voluntary nature of RTO participation by
utilities and set minimum characteristics and functions that must be met by
utilities that participate in an RTO, including exclusive and independent
authority to propose rates, terms and conditions of transmission service
provided over the facilities it operates. The order provides for an open,
flexible structure for RTOs to meet the needs of the market and provides for
the possibility of incentive ratemaking and other benefits for utilities that
participate in an RTO.
As a result of these rulemakings, on October 16, 2000, Duke Energy and two
other investor-owned utilities, Progress Energy and South Carolina Electric &
Gas, filed with the FERC to establish GridSouth Transco, LLC (GridSouth), as an
RTO. If approved, GridSouth will be a for-profit, independent transmission
company, responsible for operating and planning the companies' combined
transmission systems. The target date for formation of GridSouth is December
15, 2001. However, the actual date that GridSouth becomes operational will
depend upon the resolution of all necessary regulatory approvals and resolving
all technical issues. Management believes that the establishment of GridSouth
will not have a 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 in all 50 states and in
the District of Columbia. These restructurings 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. During
1999, three electric utility restructuring bills were filed in South Carolina's
House of Representatives. All three bills addressed competition while allowing
utilities to recover stranded costs, and have transition and phase-in periods
ranging from five to six years. A task force formed by the South Carolina
Senate is also examining issues related to deregulation of the state's electric
utility business. Legislators anticipate that legislation is likely to be
introduced during 2001. This task force will prepare a report for review,
discussion and possible legislative action by the state's Senate Judiciary
Committee and General Assembly as a whole.
In May 1997, North Carolina passed a bill that established a study
commission to examine whether competition should be implemented in the state.
Members of this commission include legislators, customers, utilities and a
member of an environmental group. The study commission unanimously approved a
set of recommendations on electric restructuring in April 2000. The
commission's report to the legislature containing these recommendations was
submitted to the General Assembly in May. The report basically recommended
retail deregulation beginning partially in 2005 and fully in 2006. However,
recent events in California's power market have led the study commission to
evaluate whether, and to what extent, proposed legislation should be introduced
in 2001. 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
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of these regulatory assets related to Franchised Electric is approximately $1.2
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. On February 9, 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 pipeline
customers for an experimental 2 1/2-year period ending September 1, 2002, and
requiring that interstate pipelines 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 the third quarter of 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 February 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 2000, Duke Energy's interstate pipelines made the
required pro forma tariff sheet filings. These filings are currently subject to
review and approval by the FERC.
Management does not believe the effects of these matters will have a
material 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. Natural gas retail deregulation is in the very
early stages of development and management cannot estimate the effects of this
matter on 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. Duke
Energy contributes to an external decommissioning trust fund and maintains an
internal reserve to fund these costs.
The balance of the external fund as of December 31, 2000 and 1999, was $717
million and $703 million, respectively. The balance of the internal reserve as
of December 31, 2000 and 1999, was $231 million and $223 million, respectively,
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
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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 for additional information.
The external decommissioning trust fund is invested primarily in domestic
and international equity securities, fixed-rate, fixed-income securities and
cash and cash equivalents. 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 Re-licensing. In May 2000, the Nuclear Regulatory Commission renewed
the operating license for Duke Energy's three Oconee nuclear units through 2033
to 2034. Licenses for Duke Energy's other nuclear units expire between 2021 and
2026 and are also available for renewal.
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 was an operator of
manufactured gas plants until the early 1950s and has entered into a
cooperative effort with the State of North Carolina and other owners of certain
former manufactured gas plant sites to investigate and, where necessary,
remediate these contaminated sites. Duke Energy is considered by regulators to
be a potentially responsible party and may be subject to future liability at
eight federal Superfund sites and three state Superfund sites. While the cost
of remediation of these sites may be substantial, Duke Energy will share in any
liability associated with remediation of contamination at such sites with other
potentially responsible parties. Management believes that resolution of these
matters will not have a material adverse effect on consolidated results of
operations, cash flows or financial position.
PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In June
1999, the Environmental Protection Agency (EPA) certified that TETCO, a wholly
owned subsidiary of Duke Energy, had completed cleanup of PCB-contaminated
sites under conditions stipulated by a U.S. Consent Decree in 1989. TETCO was
required to continue groundwater monitoring on a number of sites for two years.
This required monitoring was completed as of the end of 2000, pending EPA
concurrence. TETCO will be evaluating and discussing with the EPA, appropriate
state authorities or both the need for additional remediation or monitoring.
Under terms of the sales agreement with CMS discussed in Note 2 to the
Consolidated Financial Statements, 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 operations, management believes the resolution of matters
relating to the environmental issues discussed above will not have a material
adverse effect on consolidated results of operations, cash flows or financial
position.
Air Quality Control. The Clean Air Act (CAA) Amendments of 1990 required a
two-phase reduction by electric utilities in aggregate annual emissions of
sulfur dioxide and nitrogen oxide by 2000. All projects associated with these
requirements have been completed and Duke Energy currently meets all
requirements of Phase I and Phase II.
In October 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's rule was challenged in court by various states,
industry and other interests, including the states of North Carolina and South
Carolina, and Duke Energy. In March 2000, the court upheld most aspects of the
EPA's rule. The same court subsequently issued a decision that extended the
compliance deadline for implementation of emission reductions to May 31, 2004.
In January 2000, the EPA
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finalized another ozone-related rule under Section 126 of the CAA that has
virtually identical emission control requirements as its October 1998 action,
but with a May 1, 2003 compliance date. The EPA's 2000 rule has been challenged
in court. The court is expected to issue its decision during the spring of
2001.
In response to the EPA's October 1998 rule, both North Carolina and South
Carolina are in the process of finalizing the SIP revisions to implement the
EPA rule's emission reduction requirements. Additionally, North Carolina has
adopted a separate rule that caps nitrogen oxide emissions from coal-fired
power plants in the event the EPA's SIP rule is eventually overturned.
Depending on the resolution of these and related matters, management
anticipates that costs to Duke Energy may range from $500 million to $900
million in capital costs for additional emission controls over an estimated
time period which continues through 2007. Emission control retrofits of this
type 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.
On December 22, 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 is claiming 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 requests,
among other things, that the court enjoin Duke Energy from operating the coal-
fired units identified in the complaint, and order Duke Energy to install
additional emission controls and pay unspecified civil penalties. This
complaint appears to be 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 intends to defend itself vigorously against these
alleged violations. However, 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. Several subsequent meetings have been
held attempting to resolve operational details to clear the way for
multinational ratification and implementation without resolution. If the Kyoto
Protocol were to be adopted in its current form, 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 with those developing
public policy initiatives and continuously assesses the commercial implications
for its markets around the world.
California Issues. California Litigation. Duke Energy's subsidiaries, DENA
and DETM, have been named among 16 defendants in a class action lawsuit (the
Gordon lawsuit) filed against companies identified as "generators and traders"
of electricity in California markets. DETM also was named as one of numerous
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defendants in four additional lawsuits, including two class actions (the
Hendricks and Pier 23 Restaurant lawsuits), filed against generators, marketers
and traders and other unnamed providers of electricity in California markets.
These suits were brought either by or on behalf of electricity consumers in the
State of California. The Gordon and Hendricks class action suits were filed in
the Superior Court of the State of California, San Diego County, in November
2000. The other three suits were filed in January 2001, one in the Superior
Court of the State of California, San Diego County, and the other two in the
Superior Court of the State of California, County of San Francisco. These suits
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. Plaintiffs in the Gordon suit seek
aggregate damages of over $4 billion, and the plaintiffs in the other suits, to
the extent damages are specified, allege damages in excess of $1 billion. The
lawsuits each seek the disgorgement of alleged unlawfully obtained revenues for
sales of electricity and, in three suits, an award of treble damages.
California Wholesale Electricity Markets. As a result of high prices in the
western U.S. wholesale electricity markets in 2000, several state and federal
regulatory investigations and complaints have commenced to determine the causes
of the prices and potentially to recommend remedial action. The FERC concluded
its investigation by issuing on December 15, 2000, an Order Directing Remedies
in California Wholesale Electricity Markets. In this conclusion, the FERC found
no basis in allegations made by government officials in California that
specific electric generators artificially drove up power prices. This
conclusion is consistent with similar findings by the Compliance Unit of the
California Power Exchange (CalPX) and the Northwest Power Planning Council.
That Order is the subject of numerous rehearing requests.
At the state level, the California Public Utilities Commission, the
California Electricity Oversight Board, the California Bureau of State Audits
and the California Office of the Attorney General all have separate ongoing
investigations into the high prices and their causes. None of those
investigations have been completed and no findings have been made in connection
with any of them.
California Utilities Defaults and Other Proceedings. Two California electric
utilities recently defaulted on many of their obligations to suppliers and
creditors. NAWE supplies electric power to these utilities directly and
indirectly through contracts through the California Independent System Operator
(CAISO) and the CalPX. NAWE also supplies natural gas to these utilities under
direct contracts. With respect to electric power sales through the CAISO and
CalPX, Duke Energy quantified its exposures at December 31, 2000 to these
utilities and recorded a $110 million provision. As a result of these defaults
and certain related government actions, Duke Energy has taken a number of
steps, including initiating court actions, to mitigate its exposure.
While these matters referenced above are in their earliest stages,
management does not believe, based on its analysis to date of the factual
background and the claims asserted in these matters, that their resolution will
have a material adverse effect on Duke Energy's consolidated results of
operations, cash flows or financial position.
Litigation and Contingencies. Exxon Mobil Corporation Arbitration. In
December 2000, three subsidiaries of Duke Energy initiated binding arbitration
against three subsidiaries of the Exxon Mobil Corporation (collectively, the
"Exxon Mobil entities") concerning the parties' joint ownership of DETM and
certain related affiliates (collectively, the "Ventures"). At issue is a buy-
out right provision in the parties' agreement. The agreements governing the
ownership of the Ventures contain provisions giving Duke Energy the right to
purchase the Exxon Mobil entities' 40% interest in the Ventures in the event
material business disputes arise between the Ventures' owners. Such disputes
have arisen, and consequently, Duke Energy exercised its right to buy the Exxon
Mobil entities' interest. 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 also complains of the
Exxon Mobil entities' lack of use of, and contributions to, the Ventures.
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In January 2001, the Exxon Mobil entities asserted counterclaims in the
arbitration and claims in a separate Texas state court action alleging that
Duke Energy breached its obligations to the Ventures and to the Exxon Mobil
entities. The Exxon Mobil entities also claim that Duke Energy violated a
Guaranty Agreement. While this matter is in its early stages, management
believes that the final disposition of this action will not have a material
adverse effect on Duke Energy's consolidated results of operations, cash flows
or financial position.
For information concerning litigation and other commitments and
contingencies, see Note 14 to the Consolidated Financial Statements.
New Accounting Standard. In June 1998, Statement of Financial Accounting
Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities," was issued. Duke Energy was required to adopt this standard by
January 1, 2001. SFAS No. 133 requires that all derivatives be recognized as
either assets or liabilities and measured at fair value, and changes in the
fair value of derivatives are reported in current earnings, unless the
derivative is designated and effective as a hedge. If the intended use of the
derivative is to hedge the exposure to changes in the fair value of an asset, a
liability or a firm commitment, then changes in the fair value of the
derivative instrument will generally be offset in the income statement by
changes in the hedged item's fair value. However, if the intended use of the
derivative is to hedge the exposure to variability in expected future cash
flows, then changes in the fair value of the derivative instrument will
generally be reported in Other Comprehensive Income (OCI). The gains and losses
on the derivative instrument that are reported in OCI will be reclassified to
earnings in the periods in which earnings are impacted by the hedged item.
Duke Energy has determined the effect of implementing SFAS No. 133 and
recorded a net-of-tax cumulative-effect adjustment of $96 million as a
reduction in earnings. The net-of-tax cumulative-effect adjustment reducing OCI
and Common Stockholders' Equity is estimated to be $921 million on January 1,
2001.
Currently, there are ongoing discussions surrounding the implementation and
interpretation of SFAS No. 133 by the Financial Accounting Standards Board's
Derivatives Implementation Group. Duke Energy implemented SFAS No. 133 based on
current rules and guidance in place as of January 1, 2001. However, if the
definition of derivative instruments is altered, this may impact Duke Energy's
transition adjustment amounts and subsequent reported operating results.
Forward-Looking Statements. From time to time, Duke Energy's reports,
filings and other public announcements may include 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. Duke Energy cautions that assumptions,
projections, expectations, intentions or beliefs about future events may and
often do vary from actual results and the differences between assumptions,
projections, expectations, intentions or beliefs and actual results can be
material. Accordingly, there can be no assurance that actual results will not
differ materially from those expressed or implied by the forward-looking
statements. Some of the factors that could cause actual achievements and events
to differ materially from those expressed or implied in such forward-looking
statements include 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; growth in opportunities for Duke
Energy's business units; and the effect of accounting policies issued
periodically by accounting standard-setting bodies.
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