Exhibit 99(b)
Management's Discussion and Analysis of Results of Operations and
Financial Condition
INTRODUCTION
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 United States and abroad. Duke Energy provides these and other
services through seven business segments:
o Electric Operations
o Natural Gas Transmission
o Field Services
o Trading and Marketing
o Global Asset Development
o Other Energy Services
o Real Estate Operations
These segments were defined as a result of Duke Energy adopting Statement
of Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information."
Electric Operations generates, transmits, distributes and sells electric
energy in central and western North Carolina and the western portion of South
Carolina (doing business as Duke Power or 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, through its Northeast Pipelines, provides
interstate transportation and storage of natural gas for customers primarily in
the Mid-Atlantic and New England states. Until the expected sale of the Midwest
Pipelines in early 1999, Natural Gas Transmission also provides interstate
transportation and storage services in the midwest states. See further
discussion of the proposed sale of the Midwest Pipelines in the Liquidity and
Capital Resources section of Management's Discussion and Analysis. The
interstate natural gas transmission and storage operations are also subject to
the rules and regulations of the FERC.
Field Services gathers, processes, transports and markets natural gas and
produces and markets natural gas liquids (NGL). Field Services operates
gathering systems in ten states that serve major gas-producing regions in the
Rocky Mountain, Permian Basin, Mid-Continent and Gulf Coast areas.
Trading and Marketing markets natural gas, electricity and other
energy-related products across North America. Duke Energy owns a 60% interest
in Trading and Marketing's operations, with Mobil Corporation owning a 40%
minority interest.
Global Asset Development develops, owns and operates energy-related
facilities worldwide. Global Asset Development conducts its operations
primarily through Duke Energy Power Services, LLC (Duke Energy Power Services)
and Duke Energy International, LLC (Duke Energy International).
Other Energy Services provides engineering, consulting, construction and
integrated energy solutions worldwide, primarily through Duke Engineering &
Services, Inc. (Duke Engineering & Services), Duke/Fluor Daniel and
DukeSolutions, Inc. (DukeSolutions).
Real Estate Operations conducts its business through Crescent Resources,
Inc., which develops high quality commercial and residential real estate
projects and manages forest holdings in the southeastern United States.
The 1997 merger of Duke Power Company (Duke Power) and PanEnergy Corp
(PanEnergy) was accounted for as a pooling of interests; therefore, the
Consolidated Financial Statements and other financial information included in
this Annual Report for periods prior to the merger include the combined
historical financial results of Duke Power and PanEnergy. (See Note 2 to the
Consolidated Financial Statements.)
Management's Discussion and Analysis should be read in conjunction with
the Consolidated Financial Statements.
RESULTS OF OPERATIONS
In 1998, earnings available for common stockholders increased 36.5% over
1997, to $1,231 million, or $3.41 per basic share, net of an extraordinary loss
of $8 million, or $0.02 per basic share. The increase in earnings available for
common stockholders was primarily due to increased electric sales and energy
marketing activities, expansions and acquisitions, gains on sales of assets and
the absence of 1997 non-recurring merger costs. These increases were partially
offset by decreased NGL prices and increased interest expense and minority
interests.
Earnings available for common stockholders decreased 12.4% in 1997
compared to 1996, to $902 million or $2.51 per basic share in 1997 from $1,030
million or $2.85 per basic share in 1996. The decrease was due primarily to
non-recurring 1997 merger costs, 1997 severance costs, premiums associated with
the redemption and tender offer for ten issues of preferred stock and increased
nuclear expenses. Partially offsetting the decrease were lower expenses in 1997
as compared to 1996, when major storms affected Electric Operations'
distribution costs, and an extraordinary loss related to the early retirement
of debt in 1996.
Operating income for 1998 was $2,433 million compared to $1,970 million in
1997 and $2,159 million in 1996. Earnings before interest and taxes (EBIT) were
$2,647 million, $2,108 million and $2,294 million for 1998, 1997 and 1996,
respectively. Operating income and earnings before interest and taxes,
excluding the effect of gains on asset sales of $34 million by Field Services
in 1998, are affected by the same fluctuations for Duke Energy and each of its
business segments. Earnings before interest and taxes by business segment are
summarized below and are discussed by business segment thereafter.
Earnings Before Interest and Taxes by Business Segment
Years Ended December 31,
-----------------------------
1998 1997 1996
--------- --------- ---------
In millions
Electric Operations .............. $1,513 $1,282 $1,419
Natural Gas Transmission ......... 702 624 595
Field Services ................... 76 157 152
Trading and Marketing ............ 122 44 58
Global Asset Development ......... 80 5 --
Other Energy Services ............ 10 18 20
Real Estate Operations ........... 142 98 88
Other Operations ................. 2 (120) (38)
------ ------ ------
Consolidated EBIT ................ $2,647 $2,108 $2,294
====== ====== ======
Other Operations primarily includes communication services, water services
and certain unallocated corporate costs. Included in the amounts discussed
below are intercompany transactions that are eliminated in the Consolidated
Financial Statements.
Electric Operations
Years Ended December 31,
-----------------------------
1998 1997 1996
--------- --------- ---------
Dollars in millions
Operating Revenues .................... $4,626 $4,401 $4,498
Operating Expenses .................... 3,228 3,221 3,195
------ ------ ------
Operating Income ...................... 1,398 1,180 1,303
Other Income, Net of Expenses ......... 115 102 116
------ ------ ------
EBIT .................................. $1,513 $1,282 $1,419
====== ====== ======
Volumes, Sales -- GWh (a) ............. 82,011 77,935 77,547
- ---------
(a) Gigawatt-hour
In 1998, earnings before interest and taxes for Electric Operations
increased 18.0% to $1,513 million from $1,282 million in 1997, primarily due to
a 5.2% increase in gigawatt-hour sales. The increase in earnings before
interest and taxes due to the absence of 1997 severance costs was substantially
offset by 1998 severance and other costs related to the shut-down of Electric
Operations' merchandising business.
Sales to weather-sensitive customers increased significantly in 1998
compared to 1997, which was a mild weather year, with sales to residential and
general service customers up 7.5% and 7.1%, respectively, primarily due to
warmer spring and summer weather conditions. On July 21, 1998, Electric
Operations customers set the third record demand of the summer, reaching a peak
of 15,812 megawatts. Sales to industrial customers increased slightly in 1998
over 1997, with sales to textile customers relatively flat. The number of
customers in the Electric Operations service territory increased 2.5% in 1998
over 1997 due to economic growth in the region.
In 1997, earnings before interest and taxes for Electric Operations
declined 9.7% as compared to 1996, primarily as a result of severance costs and
increased nuclear outage expenses. Also contributing to the decrease were lower
electric revenues, which were due primarily to mild weather and to the South
Carolina rate reduction, which was effective June 1, 1996. Partially offsetting
the decrease in earnings were lower expenses in 1997 as compared to 1996, when
major storms affected distribution costs.
Natural Gas Transmission
Years Ended December 31,
-----------------------------
1998 1997 1996
--------- --------- ---------
Dollars in millions
Operating Revenues ...................... $1,528 $1,572 $1,556
Operating Expenses ...................... 864 964 973
------ ------ ------
Operating Income ........................ 664 608 583
Other Income, Net of Expenses ........... 38 16 12
------ ------ ------
EBIT .................................... $ 702 $ 624 $ 595
====== ====== ======
Volumes, Throughput -- TBtu (a) ......... 2,593 2,862 2,939
- ---------
(a) Trillion British thermal units
Earnings before interest and taxes for Natural Gas Transmission increased
$78 million in 1998 over 1997. Earnings before interest and taxes for Northeast
Pipelines increased $56 million to $476 million in 1998 compared to 1997,
primarily as a result of the favorable resolution of regulatory issues related
to gas supply realignment costs, favorable state property tax rulings and
increased market expansion projects. These increases were partially offset by a
decrease in throughput primarily as a result of mild winter weather.
In 1998, earnings before interest and taxes for Midwest Pipelines
increased 10.8% compared to 1997, primarily due to a gain on the sale of the
general partner interests in Northern Border Partners, L.P. and non-recurring
1997 litigation expenses. These increases were partially offset by the
favorable resolution of certain regulatory matters in 1997, which was reflected
as additional revenue and other income. See the Liquidity and Capital Resources
- -- Investing Cash Flows section of Management's Discussion and Analysis for a
discussion of the expected sale of the Midwest Pipelines in early 1999. (See
also Note 14 to the Consolidated Financial Statements.)
Earnings before interest and taxes for Natural Gas Transmission increased
4.9% in 1997 over 1996, with increases in earnings at Northeast Pipelines and
Midwest Pipelines of 5.3% and 4.0%, respectively. Earnings before interest and
taxes for the Northeast Pipelines increased primarily due to market-expansion
projects placed in service.
For the Midwest Pipelines, earnings before interest and taxes increased
primarily due to the favorable resolution of certain regulatory matters in 1997
in amounts in excess of those resolved in 1996, which was reflected as
additional revenue and other income. This increase was partially offset by 1997
litigation expenses.
Field Services
Years Ended December 31,
--------------------------------------
1998 1997 1996
------------ ------------ ------------
Dollars in millions
Operating Revenues ........................................ $ 2,639 $ 3,055 $ 2,637
Operating Expenses ........................................ 2,598 2,898 2,487
-------- -------- --------
Operating Income .......................................... 41 157 150
Other Income, Net of Expenses ............................. 35 -- 2
-------- -------- --------
EBIT ...................................................... $ 76 $ 157 $ 152
======== ======== ========
Volumes
Natural Gas Gathered and Processed/Transported, TBtu/d (a) 3.6 3.4 2.9
Natural Gas Marketed, TBtu/d .............................. 0.4 0.4 0.5
NGL Production, MBbl/d (b) ................................ 110.2 108.2 78.5
- ---------
(a) Trillion British thermal units per day
(b) Thousand barrels per day
In 1998, earnings before interest and taxes for Field Services decreased
$81 million compared to 1997, primarily due to a decrease in average NGL prices
of approximately $0.09 per gallon, or 25.7%. The decrease in earnings before
interest and taxes was partially offset by $34 million of gains on sales of
assets which are included in other income.
Earnings before interest and taxes for Field Services increased 3.3% in
1997 over 1996, primarily due to higher volumes as a result of acquisitions in
1996. Natural gas gathered and processed volumes increased 17.2%, and NGL
production increased 37.8% in 1997 compared to 1996. Partially offsetting these
increases were lower NGL prices of approximately $0.04 per gallon, or 8%, and
higher natural gas prices.
Trading and Marketing
Years Ended December 31,
-----------------------------------
1998 1997 1996
----------- ----------- -----------
Dollars in millions
Operating Revenues .................... $8,785 $7,489 $3,814
Operating Expenses .................... 8,665 7,446 3,758
------ ------ ------
Operating Income ...................... 120 43 56
Other Income, Net of Expenses ......... 2 1 2
------ ------ ------
EBIT .................................. $ 122 $ 44 $ 58
====== ====== ======
Volumes
Natural Gas Marketed, TBtu/d .......... 8.0 6.9 5.5
Electricity Marketed, GWh ............. 98,991 64,650 4,229
In 1998, earnings before interest and taxes for Trading and Marketing
increased $78 million over 1997. The increase resulted primarily from increased
financial trading margins and electricity margins, partially offset by
increased expenses due to business growth. Electricity volumes marketed
increased primarily as a result of acquiring the remaining 50% ownership
interest in the Duke/Louis Dreyfus, L.L.C. (D/LD) joint venture in June 1997.
Earnings before interest and taxes for Trading and Marketing decreased $14
million in 1997 compared to 1996. The acquisition of the remaining 50%
ownership interest in the D/LD joint venture in 1997, coupled with a full year
of operations of the joint venture with Mobil Corporation formed in August
1996, accounted for the significant increases in Trading and Marketing
revenues, related operating expenses (including increased purchased power
expense) and volumes in 1997 over 1996. Increased natural gas volumes marketed
of 25.5% in 1997, in addition to increased natural gas margins from trading
activities, were largely offset by the emerging electric power trading and
marketing activities. Higher operating expenses, due primarily to increased
personnel levels and system development costs to provide the necessary
infrastructure for growth in the trading and marketing business, resulted in a
decrease in earnings before interest and taxes in 1997 as compared to 1996.
Global Asset Development
Years Ended December 31,
-------------------------------
1998 1997 1996
-------- ----------- ----------
In millions
Operating Revenues .................... $ 319 $ 123 $ 72
Operating Expenses .................... 261 129 73
----- ----- ----
Operating Income ...................... 58 (6) (1)
Other Income, Net of Expenses ......... 22 11 1
----- ----- -----
EBIT .................................. $ 80 $ 5 $ --
===== ===== =====
In 1998, earnings before interest and taxes for Global Asset Development
increased $75 million over 1997. The increase results primarily from business
expansion and acquisitions, including Duke Energy Power Services' July 1, 1998
acquisition of three electric generating stations in California from Pacific
Gas & Electric Company (PG&E) and December 1997 acquisition of an indirect
32.5% ownership interest in American Ref-Fuel Company. Duke Energy
International also contributed to the increase in earnings before interest and
taxes in 1998 compared to 1997 through an expansion to the PT Puncakjaya power
generation facility in Indonesia. This increase was partially offset by
decreased earnings resulting from lower prices at National Methanol, a methanol
and MTBE (methyl tertiary butyl ether) plant in Saudi Arabia.
In 1997, earnings before interest and taxes increased slightly compared to
1996, due primarily to business expansion and acquisitions, including the
December 1997 acquisition of an ownership interest in American Ref-Fuel
Company, and a gain on the sale of an investment. These increases were
partially offset by increased expenses due to business growth.
Other Energy Services
Years Ended December 31,
-----------------------------
1998 1997 1996
-------- ----------- --------
In millions
Operating Revenues .................... $ 521 $ 376 $ 204
Operating Expenses .................... 511 353 184
----- ----- -----
Operating Income ...................... 10 23 20
Other Income, Net of Expenses ......... -- (5) --
----- ----- -----
EBIT .................................. $ 10 $ 18 $ 20
===== ===== =====
In 1998, earnings before interest and taxes for Other Energy Services
decreased $8 million compared to 1997, primarily due to decreased earnings of
Duke Engineering & Services. Earnings before interest and taxes for Other
Energy Services decreased $2 million in 1997 compared to 1996, primarily as a
result of start-up expenses of DukeSolutions partially offset by increased
earnings of Duke Engineering & Services due to growth.
Real Estate Operations
Years Ended December 31,
--------------------------
1998 1997 1996
-------- -------- --------
In millions
Operating Revenues .................... $ 181 $ 124 $ 114
Operating Expenses .................... 39 26 26
----- ----- -----
Operating Income ...................... 142 98 88
Other Income, Net of Expenses ......... -- -- --
----- ----- -----
EBIT .................................. $ 142 $ 98 $ 88
===== ===== =====
In 1998, earnings before interest and taxes for Real Estate Operations
increased 44.9% compared to 1997, primarily as a result of increased project
and lake lot sales and a gain on land sales in the Jocassee Gorges region of
South Carolina. Earnings before interest and taxes for Real Estate Operations
increased 11.4% in 1997 over 1996, primarily due to gains associated with bulk
land sales in 1997.
Other Operations
Earnings before interest and taxes for Other Operations increased in 1998
compared to 1997, primarily as a result of the absence of $71 million of
non-recurring 1997 merger-related costs and the favorable resolution of certain
contingent items in 1998. The increase in earnings before interest and taxes
was partially offset by a 1997 gain on the sale of the ownership interest in
the Midland Cogeneration Venture.
Earnings before interest and taxes for Other Operations declined $82
million in 1997 compared to 1996. Contributing to the decrease were increased
merger-related expenses of $57 million in 1997 compared to 1996 and the 1997
amortization of goodwill associated with the purchase of the remaining 50%
ownership interest in the D/LD joint venture. This decline was partially offset
by the sale of the ownership interest in the Midland Cogeneration Venture in
1997.
Other Impacts on Earnings Available for Common Stockholders
Interest expense increased 8.9% in 1998 over 1997 due to higher average
debt balances outstanding. In 1997, interest expense decreased $27 million, or
5.4%, as compared to 1996 as a result of lower interest rates.
In 1998, minority interests increased $73 million compared to 1997. This
increase includes 1998 dividends for trust preferred securities, of which $350
million were issued in December 1997 and $600 million were issued in 1998. See
further discussion of the 1998 issuances of trust preferred securities in the
Liquidity and Capital Resources section of Management's Discussion and
Analysis. Excluding these dividends, minority interests relate primarily to the
trading and marketing joint venture with Mobil Corporation formed in August
1996.
In January 1998, TEPPCO Partners, L.P., in which a subsidiary of Duke
Energy has a 2% general partner interest and a 19.1% limited partner interest,
redeemed certain First Mortgage Notes. A non-cash extraordinary loss of $8
million, net of income tax of $5 million, was recorded related to costs of the
early retirement of that debt.
On October 1, 1996, a subsidiary of Duke Energy redeemed its $150 million,
10% debentures and its $100 million, 10 1/8% debentures, both due 2011. A
non-cash extraordinary loss of $17 million, net of income tax of $10 million,
was recorded related to the unamortized discount on this early retirement of
debt.
In December 1997, Duke Energy redeemed four issues of preferred stock and
commenced a tender offer to purchase a portion of an additional six issues of
preferred stock. Premiums related to these redemptions were included in the
Consolidated Statements of Income in 1997 as Dividends and Premiums on
Redemptions of Preferred and Preference Stock.
LIQUIDITY AND CAPITAL RESOURCES
Operating Cash Flows. Assets and liabilities recorded in the Consolidated
Balance Sheets related to purchased capacity levelization and natural gas
transition cost recoveries and the related cash flow impacts are affected by
state and federal regulatory initiatives and specific agreements. For more
information on the purchased capacity levelization and the natural gas
transition cost recoveries, see Notes 5 and 4, respectively, to the
Consolidated Financial Statements.
On August 29, 1998, the FERC approved a settlement from Texas Eastern
Transmission Corporation (TETCO), a subsidiary of Duke Energy, which will
accelerate recovery of natural gas transition costs and reduce depreciation
expense to more appropriately reflect the estimated useful lives of its
facilities, principally interstate natural gas pipelines. The order was
effective October 1, 1998 and includes a rate moratorium until 2004. Cash flows
from operations are not expected to change for the first two years after
implementation due to the offsetting effect on customer rates of the reduced
depreciation expense and increased recovery of natural gas transition costs.
When the natural gas transition costs are fully recovered, cash flows from
operations are expected to decrease during 2001 through 2003 by an estimated
total of $270 million. For more information concerning the settlement, see Note
4 to the Consolidated Financial Statements.
Investing Cash Flows. Capital and investment expenditures were
approximately $2.5 billion in 1998 compared to approximately $2.0 billion in
1997. This increase was primarily due to business expansion by Global Asset
Development, which included Duke Energy Power Services' $501 million purchase
of three electric generating stations in California from PG&E and the
completion of the first phase of Bridgeport Energy, a $265 million,
520-megawatt combined cycle natural gas-fired merchant generation plant.
Business expansion for Natural Gas Transmission and Field Services also
contributed to the increase in capital and investment expenditures. The
increase was partially offset by decreased expenditures for Electric
Operations, primarily as a result of steam generator replacements at certain of
its nuclear plants in 1997, and by the acquisition of the remaining 50%
ownership of the D/LD joint venture in June 1997.
Capital and investment expenditures in 1997 included the acquisition of
the remaining 50% ownership interest in the D/LD joint venture for $247
million, which substantially represented goodwill, and Global Asset
Development's acquisition of an ownership interest in American Ref-Fuel Company
for $237 million. The increase in capital and investment expenditures in 1997
over 1996 also included increased Electric Operations construction costs,
primarily due to steam generator replacements at certain of its nuclear plants
and increased distribution line construction, and business expansion for the
Natural Gas Transmission segment. These increases were partially offset by the
1996 acquisition of certain assets from Mobil Corporation.
Duke Energy plans to maintain its regulated electric operations facilities
in the Carolinas and pursue business expansion as opportunities arise.
Projected 1999 capital and investment expenditures for Electric Operations,
including allowance for funds used during construction, are approximately $900
million. These projections include expenditures for existing plants, including
refurbishment and upgrades related to the Oconee Nuclear Station's application
for a 20-year renewal of its operating license. The license renewal process
could take three to five years to complete. All projections are subject to
periodic review and revisions. Actual expenditures incurred may vary from such
estimates due to various factors, including industry restructuring, weather,
economic growth, regulatory constraints and environmental regulation.
Projected 1999 capital and investment expenditures for Natural Gas
Transmission, including allowance for funds used during construction, are
approximately $400 million which do not include projections related to the
Midwest Pipelines which are expected to be sold in early 1999. These
projections include the completion of the Maritimes & Northeast Pipeline
project, which will deliver natural gas to markets in the Canadian Maritimes
provinces and the northeastern United States from a supply basin offshore Nova
Scotia. These projections also include other market expansion projects and
costs relating to existing assets.
Duke Energy plans to continue to significantly grow several of its
business segments: Field Services, Global Asset Development, Trading and
Marketing and Other Energy Services. Expansion opportunities for Field Services
include the planned $1.35 billion acquisition of the natural gas gathering,
processing, fractionation and NGL pipeline business of Union
Pacific Resources along with its natural gas and NGL marketing activities. The
transaction is expected to close in the first half of 1999 and is contingent
upon completion of due diligence and receipt of clearances under the
Hart-Scott-Rodino Act.
Expansion opportunities for Global Asset Development's international
division, Duke Energy International, include the $315 million purchase of power
generation and transmission assets in western Australia and New Zealand,
including an ownership interest in a pipeline in western Australia. This
acquisition also includes a development proposal for a cogeneration plant and a
portfolio of international and Australian-based projects. This transaction
closed on January 22, 1999.
Also, Duke Energy International recently purchased the rights to develop
and operate the 500-mile Eastern Gas Pipeline project in eastern Australia.
Construction of this $270 million pipeline project is scheduled to begin in
July 1999 and completion is expected by the middle of 2000.
Expansion opportunities for Global Asset Development's domestic division,
Duke Energy Power Services, include the continuation of greenfield projects,
such as the Bridgeport Energy project and the Maine Independence Station, a
520-megawatt combined cycle natural gas-fired merchant generation plant in
Maine which is scheduled to begin producing power in the summer of 2000. Other
expansion opportunities include the Hidalgo project, a 510-megawatt power plant
to be built in south Texas, which is targeted to begin producing power in
mid-2000. Other similar initiatives in 1999 for both Duke Energy International
and Duke Energy Power Services will likely require significant capital and
investment expenditures, which will be subject to periodic review and revision
and may vary significantly depending on the value-added opportunities
presented.
Projected 1999 capital and investment expenditures for Trading and
Marketing, Other Energy Services and Real Estate Operations are approximately
$30 million, $90 million and $300 million, respectively. All projected capital
and investment expenditures are subject to periodic review and revision and may
vary significantly depending on acquisition opportunities, market volatility,
economic trends and the value-added opportunities presented.
In October 1998, Duke Energy, through its wholly owned subsidiaries,
PanEnergy and Texas Eastern Corporation, entered into an agreement to sell
Panhandle Eastern Pipe Line Company (PEPL), Trunkline Gas Company (Trunkline)
and additional storage related to those systems, which substantially comprise
the Midwest Pipelines, along with Trunkline LNG Company, to CMS Energy
Corporation. The sales price of $2.2 billion involves cash proceeds of $1.9
billion and the assumption of existing PEPL debt of approximately $300 million.
The sale is expected to close in early 1999 and will result in an after-tax
gain of approximately $700 million. The sale is contingent upon receipt of
clearances under the Hart-Scott-Rodino Act.
Financing Cash Flows. Duke Energy's consolidated capital structure at
December 31, 1998, including short-term debt, was 43.3% debt, 5.5% trust
preferred securities, 2.0% preferred stock and 49.2% common equity. Fixed
charges coverage, calculated using the Securities and Exchange Commission
method, was 4.7 times, 4.1 times and 4.3 times for 1998, 1997 and 1996,
respectively.
Duke Energy plans to continue to significantly grow several of its
business segments: Field Services, Trading and Marketing, Global Asset
Development and Other Energy Services. These growth opportunities, along with
dividends, debt repayments and operating and investing requirements, are
expected to be funded by cash from operations, external debt financing and the
proceeds from the sale of the Midwest Pipelines.
Securities Ratings
Duke Energy Corporation S&P Moody's Fitch Duff & Phelps
First and Refunding Mortgage Bonds AA- Aa3 AA- AA
Senior Unsecured A A1 A+ AA-
Preferred Stock A a1 A+ A+
Trust Preferred Securities A a1 A+ A+
Commercial Paper A-1 P-1 F-1+ D-1+
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 June 1998 that targets 50% of earnings paid out in dividends
on common stock. Prior to the adoption of the policy, approximately 65% of
earnings were paid out in dividends. The Board of Directors intends to maintain
dividends at the current quarterly rate of $0.55 per share until the target
payout ratio is reached.
In February 1998, Duke Energy completed its tender offer for a maximum of
50% of the outstanding shares of six of its preferred stock issues, purchasing
two million shares of its preferred stock for $180 million.
Duke Capital Corporation (Duke Capital) is a wholly owned subsidiary of
Duke Energy and serves as the parent for Duke Energy's business segments except
Electric Operations and certain other operations. In July 1998, Duke Capital
issued $400 million of Senior Unsecured Notes. Also, during 1998, Duke
Capital's business trusts, which are treated as indirect wholly owned
subsidiaries of Duke Energy for financial reporting purposes, issued $600
million of trust preferred securities. (See Note 12 to the Consolidated
Financial Statements.)
In December 1998, Duke Energy issued $300 million of Senior Unsecured
Notes. The proceeds, along with $200 million in commercial paper, were used to
redeem $500 million of First and Refunding Mortgage Bonds, which were called on
December 31, 1998. In January 1999, Duke Energy issued $200 million of Senior
Notes.
Under its commercial paper facilities, Duke Energy had the ability to
borrow up to $2.8 billion and $2.5 billion as of December 31, 1998 and 1997,
respectively. At December 31, 1998, the commercial paper facilities consisted
of $1.25 billion for Duke Energy and $1.55 billion for Duke Capital. At
December 31, 1997, the commercial paper facilities consisted of $1.25 billion
each for Duke Energy and Duke Capital. At December 31, 1998 and 1997, Duke
Energy's various bank credit facilities totaled approximately $2.9 billion and
$2.7 billion, respectively. At December 31, 1998, $1.9 billion was outstanding
under the commercial paper facilities and $100 million was outstanding under
the bank credit facilities.
As of December 31, 1998, Duke Energy and its subsidiaries, excluding PEPL,
had authority to issue up to $1.2 billion aggregate principal amount of debt
and other securities under shelf registrations filed with the Securities and
Exchange Commission. Such securities may be issued as First and Refunding
Mortgage Bonds, Senior Notes, Subordinated Notes or Preferred Stock. On January
27, 1999, Duke Capital filed a $1 billion shelf registration statement, which
was declared effective by the Securities and Exchange Commission on February
10, 1999.
Duke Energy used authorized but unissued shares of its common stock to
meet 1998 employee benefit plan contribution requirements instead of purchasing
shares on the open market. This practice is expected to be continued in 1999.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Policies. Duke Energy is exposed to market risks associated with
commodity prices, interest rates, equity prices and foreign exchange rates.
Comprehensive risk management policies have been established by the Corporate
Risk Management Committee (CRMC) to monitor and control these market risks. The
CRMC is chaired by the Chief Financial Officer and primarily comprises senior
executives. The CRMC has responsibility for overseeing all corporate energy
risk management and recommending energy financial exposure limits, as well as
responsibility for oversight of interest rate risk, foreign currency risk and
credit risk.
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
debt and trust preferred securities, commercial paper and auction market
preferred stock, as well as fixed-to-floating interest rate swaps and interest
rate lock agreements. Duke Energy manages its interest rate exposure by
limiting its variable-rate and fixed-rate exposure to a certain percentage of
total capitalization, as set by policy, and by monitoring the effects of market
changes in interest rates. (See Notes 1, 7, 10, 12 and 13 to the Consolidated
Financial Statements.)
If market interest rates average 1% higher (lower) in 1999 than in 1998,
interest expense would increase (decrease), and earnings before income taxes
would decrease (increase) by approximately $23 million. Comparatively, had
interest rates averaged 1% higher (lower) in 1998 than in 1997, interest
expense would have increased (decreased), and 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, 1998 and 1997. 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.
Commodity Price Risk. Duke Energy, substantially through its subsidiaries,
is exposed to the impact of market fluctuations in the price and transportation
costs of natural gas, electricity and petroleum products marketed. Duke Energy
employs established policies and procedures to manage its risks associated with
these market fluctuations using various commodity derivatives, including
futures, swaps and options. (See Notes 1 and 7 to the Consolidated Financial
Statements.) The risk in the commodity trading portfolio is measured 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 in comparison
to established thresholds. Other measures are also utilized to monitor the risk
in the commodity trading portfolio on a monthly and annual basis.
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 future market movements for natural gas, electricity and petroleum
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 calculation includes commodity
derivative instruments and forwards held for trading purposes and excludes the
effects of embedded physical options in the trading portfolio. At December 31,
1998 and 1997, the estimated potential one-day favorable or unfavorable impact
on earnings before income taxes related to commodity instruments held for
trading purposes was approximately $10 million and $2 million, respectively.
During 1998, the average estimated potential one-day favorable or unfavorable
impact on earnings before income taxes related to commodity instruments held
for trading purposes was approximately $5 million. The increase in 1998
compared to 1997 is a result of an increase in the authorized energy financial
exposure limit, which was approved by the CRMC. Changes in markets inconsistent
with historical trends could cause actual results to exceed predicted limits.
Market risks associated with commodity derivatives held for purposes other than
trading were not material at December 31, 1998 and 1997.
Subsidiaries of Duke Energy are also exposed to market fluctuations in the
prices of NGLs related to their ongoing gathering and processing operating
activities. Duke Energy closely monitors the risks associated with NGL price
changes on its future operations, and where appropriate, uses crude oil and
natural gas commodity instruments to hedge NGL prices. If NGL prices averaged
one cent per gallon less in 1998, earnings before income taxes would have
decreased by approximately $8 million. Duke Energy generally does not maintain
a material inventory of NGLs or actively trade commodity derivatives related to
NGLs.
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, 1998 and 1997, 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 affect consolidated results of
operations. See further discussion in the Current Issues, Nuclear
Decommissioning Costs section of Management's Discussion and Analysis.
Foreign Operations Risk. Duke Energy is exposed to foreign currency risk,
sovereign risk and other foreign operations risks arising from equity
investments in international affiliates and businesses owned and operated in
foreign countries. At December 31, 1998 Duke Energy had more than $100 million
invested in Australia. Investments in other foreign countries were not material
at December 31, 1998 or 1997. In order to mitigate risks associated with
foreign currency fluctuations, the majority of contracts entered into by Duke
Energy or its affiliates are denominated in or indexed to the U.S. dollar or
may be hedged through issuance of debt denominated in the foreign currency.
Duke Energy also uses foreign currency swaps, where appropriate, to manage its
risk related to foreign currency fluctuations. Other exposures to foreign
currency risk, sovereign risk or other foreign operations risk are periodically
reviewed by management and were not material to consolidated results of
operations or financial position during 1998 or 1997.
CURRENT ISSUES
Operations Outlook. Duke Energy's business strategy is to develop regional
centers of energy assets involving gas, electric generation and marketing in
the United States and internationally. In the United States, Duke Energy is
aggressively investing in new pipelines and power plants in the Northeast, Gulf
Coast and West. Internationally, Duke Energy is focusing on opportunities in
Asia Pacific, South America and Europe.
Electric Operations is expected to grow moderately, consistent with
historical trends. Expansion will primarily result from continued economic
growth in its service territory. In 1997, as a result of the merger with
PanEnergy, Duke Energy signed various agreements with the NCUC, PSCSC and the
FERC capping base rates to retail and wholesale electric customers at existing
levels through 2000. In addition, Duke Energy signed agreements with the other
joint owners of the Catawba Nuclear Station providing for a cap on certain
rates charged under interconnection agreements. In response to these rate
agreements and competitive pressures, Electric Operations continues to strive
to maintain low costs and competitive
rates for its customers and to provide high quality customer service. Duke
Energy does not expect a negative impact as a result of such agreements on its
results of operations or financial position. (See further discussion in the
Electric Competition section below.)
The Northeast Pipelines are an essential part of Natural Gas
Transmission's strategy to advance projects that provide expanded services to
meet the specific needs of customers. The proposed sale of the Midwest
Pipelines allows Natural Gas Transmission to focus on regions, such as the
northeastern U.S., with increasing demand for gas. Northeast pipeline projects
will provide transportation from new supplies in both eastern and western
Canada in addition to traditional domestic supply basins.
Duke Energy plans to significantly grow several of its business segments:
Field Services, Trading and Marketing, Global Asset Development and Other
Energy Services. Deregulation of energy markets in the United States and abroad
is providing substantial opportunities for these segments to capitalize on
their broad capabilities. Field Services will expand through the purchase of
the natural gas gathering, processing, fractionation and NGL pipeline business
from Union Pacific Resources along with its natural gas and NGL marketing
activities.
Global Asset Development expects to continue strong growth through
acquisitions, construction of greenfield projects and expansion of existing
facilities as value-added opportunities present themselves. Duke Energy's
combination of assets and capabilities that span the energy value chain have
contributed to Global Asset Development's successful combination of natural gas
pipeline capabilities, power generation, energy marketing and other services.
This demonstrated domestic strategy is now being deployed internationally in
the Asia Pacific area and in South America. Other Energy Services seeks to grow
with types of services including comprehensive energy efficiencies in food,
textile and government facilities.
The strong real estate market in the Southeast continues to present
substantial growth opportunities for Real Estate Operations. In 1998, Real
Estate Operations initiated development of significant office and industrial
facilities in each of its established markets to capitalize on market
conditions.
While the proposed sale of the Midwest Pipelines will provide an
opportunity to deploy capital into areas of higher growth, Duke Energy expects
to experience some near-term earnings pressure as a result of the sale. Duke
Energy believes that its strategy of developing regional centers of energy
assets will return long-term growth and increase shareholder value. Duke Energy
continues to target long-term annual growth in earnings per share of eight to
ten percent.
Electric Competition. Wholesale Competition. The Energy Policy Act of 1992
(EPACT) and the FERC's subsequent rulemaking activities have established the
regulatory framework to open the wholesale energy market to competition. EPACT
amended provisions of the Public Utility Holding Company Act of 1935 and the
Federal Power Act to remove certain barriers to a competitive wholesale market.
EPACT permits utilities to participate in the development of independent
electric generating plants for sales to wholesale customers, and also permits
the FERC to order transmission access for third parties to transmission
facilities owned by another entity. It does not, however, permit the FERC to
issue an order requiring transmission access to retail customers. The FERC,
responsible in large measure for implementation of the EPACT, has moved
vigorously to implement its mandate, interpreting the statute broadly and
issuing orders for third-party transmission service and a number of rules of
general applicability, including Orders 888 and 889.
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.
Duke Energy and several of its non-regulated subsidiaries were granted
authority by the FERC to act as power marketers in 1995. In 1998, an additional
non-regulated subsidiary was granted power marketer authority. Electric
Operations obtained from the FERC open-access rule the rights to sell capacity
and energy at market-based rates from its own assets. Open access provides
another supply option through which Electric Operations can purchase at
attractive rates a portion of capacity and energy requirements resulting in
lower overall costs to customers. Open access also provides Electric
Operations' existing wholesale customers with competitive opportunities to seek
other suppliers for their capacity and energy requirements.
Wholesale sales represented approximately 11.3% of total gigawatt-hour
sales for Electric Operations in 1998. Supplemental power sales to the other
joint owners of Catawba Nuclear Station comprised the majority of wholesale
sales. Such supplemental power sales will continue to decline in 1999 as the
joint owners retain more capacity and energy from Catawba Nuclear Station or
purchase from a third party. (See Note 5 to the Consolidated Financial
Statements.)
Retail Competition. Currently, Electric Operations operates as a
vertically integrated, investor-owned utility with exclusive rights to supply
electricity in a franchised service territory -- a 20,000-square-mile service
territory in the Carolinas. In its retail business, the NCUC and the PSCSC
regulate Electric Operations' service and rates.
Electric industry restructuring is being addressed in all 50 states and in
the District of Columbia which is resulting in changes in the industry. These
changes 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. Although the North Carolina and South
Carolina legislatures have not made a final decision on this matter,
initiatives are underway to determine whether it is in the best interests of
all parties to deregulate the electric industry.
In May 1997, North Carolina passed a bill that established a study
commission to examine whether competition should be implemented in the state.
The commission's report to the state General Assembly is expected to be
completed by early 2000. Duke Energy is a member of the study commission along
with other utility representatives, legislators, customers and a member of an
environmental group.
On February 3, 1998, the PSCSC presented its report to the South Carolina
House of Representatives on how to deregulate the electric industry. The report
leaves the final decisions to the General Assembly of South Carolina. The
Public Utility Subcommittee of the House of Representatives Committee on Labor,
Commerce and Industry has been conducting hearings regarding electric industry
restructuring during the past year.
Late in 1998, a task force was formed by the South Carolina Senate to
examine issues related to deregulation of the state's electric utility
business. This task force will prepare a report for review, discussion and
possible legislative action by the Senate Judiciary Committee and the General
Assembly as a whole.
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
Electric Operations is approximately $1.5 billion, including primarily
purchased capacity costs, debt expense and deferred taxes related to regulatory
assets. Currently, Duke Energy is recovering substantially all of these
regulatory assets through its wholesale and retail electric rates and would
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 work with customers,
legislators and regulators to address all the important issues. Management
cannot predict the potential impact, if any, of these competitive forces on
future consolidated results of operations or financial position.
Natural Gas Competition. Wholesale Competition. On July 29, 1998, the FERC
issued a Notice of Proposed Rulemaking (NOPR) on short-term natural gas
transportation services, which proposed an integrated package of revisions to
its regulations governing interstate natural gas pipelines. "Short term" has
been defined in the NOPR as all transactions of less than one year. Under the
proposed approach, cost-based regulation would be eliminated for short-term
transportation and replaced by regulatory policies intended to maximize
competition in the short-term transportation market, mitigate the ability of
companies to exercise residual monopoly power and provide opportunities for
greater flexibility providing pipeline services. The proposed changes include
initiatives to revise pipeline scheduling procedures, receipt and delivery
point policies and penalty policies, and require pipelines to auction
short-term capacity. Other proposed changes would improve the FERC's reporting
requirements, permit pipelines to negotiate rates and terms of services, and
revise certain rate and certificate policies that affect competition.
In conjunction with the NOPR, the FERC also issued a Notice of Inquiry
(NOI) on its pricing policies in the existing long-term market and pricing
policies for new capacity. The FERC seeks comments on whether its policies are
biased toward either short-term or long-term service, provide accurate price
signals and the right incentives for pipelines to provide optimal
transportation services and construct facilities that meet future demand and do
not result in over building and excess capacity. Comments on the NOPR and NOI
are due in April, 1999.
Because these notices are at a very early stage and ultimate resolution is
unknown, management cannot estimate the effects of these matters on future
consolidated results of operations or financial position.
Retail Competition. Duke Energy currently does not provide retail natural
gas service, but changes in regulation to allow retail competition could affect
Duke Energy's natural gas transportation contracts with local 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 or financial position.
Nuclear Decommissioning Costs. Duke Energy's estimated site-specific
nuclear decommissioning costs total approximately $1.3 billion stated in 1994
dollars based on decommissioning studies completed in 1994. This estimate
includes the cost of decommissioning plant components not subject to
radioactive contamination. Duke Energy contributes to an external
decommissioning trust fund and maintains an internal reserve to fund these
costs.
The balance of the external funds as of December 31, 1998 and 1997, was
$580 million and $471 million, respectively. The balance of the internal
reserve as of December 31, 1998 and 1997, was $217 million and $211 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 funding of the
decommissioning costs will not have a material adverse effect on consolidated
results of operations or financial position. (See Note 11 to the Consolidated
Financial Statements.)
As of December 31, 1998 and 1997, the external decommissioning trust fund
was invested primarily in domestic and international equity securities,
fixed-rate, fixed-income securities and cash and cash equivalents. Maintaining
a portfolio that includes long-term equity investments maximizes the returns to
be utilized to fund nuclear decommissioning, which in the long-term will better
correlate to inflationary increases in decommissioning costs. However, the
equity securities included in Duke Energy's portfolio are exposed to price
fluctuations in equity markets, and the fixed-rate, fixed-income securities are
exposed to changes in interest rates.
Duke Energy actively monitors its portfolio by benchmarking the
performance of its investments against certain indexes and by maintaining, and
periodically reviewing, established target allocation percentages of the assets
in its trusts. Because the accounting for nuclear decommissioning recognizes
that costs are recovered through the Electric Operations segment's rates,
fluctuations in equity prices or interest rates do not affect consolidated
results of operations.
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. The State of South Carolina has expressed
interest in entering into a similar arrangement. Duke Energy is considered by
regulators to be a potentially responsible party and may be subject to future
liability at seven federal Superfund sites and three state Superfund sites.
While the cost of remediation of the remaining 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 or financial position.
PCB (Polychlorinated Biphenyl) Assessment and Clean-up Programs. TETCO, a
wholly owned subsidiary of Duke Energy, is currently conducting PCB assessment
and clean-up programs at certain of its compressor station sites under
conditions stipulated by a U.S. Consent Decree. The programs include on- and
off-site assessment, installation of on-site source control equipment and
groundwater monitoring wells, and on- and off-site clean-up work. TETCO
completed the soil clean-up programs during 1998, subject to regulatory
approval. Groundwater monitoring activities will continue at several sites
beyond 1999.
In 1987, the Commonwealth of Kentucky instituted a suit in state court
against TETCO, alleging improper disposal of PCBs at TETCO's three compressor
station sites in Kentucky. This suit is still pending. In 1996, TETCO completed
clean-up of these sites under the U.S. Consent Decree.
Duke Energy has also identified environmental contamination at certain
sites on the PEPL and Trunkline systems and has undertaken clean-up programs at
these sites. The contamination resulted from the past use of lubricants
containing PCBs and the prior use of wastewater collection facilities and other
on-site disposal areas. Soil and sediment testing, to date, has detected no
significant off-site contamination. Duke Energy has communicated with the
Environmental Protection Agency (EPA) and appropriate state regulatory agencies
on these matters. Under the terms of the agreement with CMS Energy Corporation,
Duke Energy is obligated to complete the PEPL and Trunkline clean-up programs
at certain agreed-upon sites. These clean-up programs are expected to continue
until 2001.
At December 31, 1998 and 1997, remaining estimated clean-up costs on the
TETCO, PEPL and Trunkline systems were accrued and included in the Consolidated
Balance Sheets as Environmental Clean-up Liabilities. These cost estimates
represent gross clean-up costs expected to be incurred, have not been
discounted or reduced by customer recoveries and generally do not include
fines, penalties or third-party claims. Costs expected to be recovered from
customers have been deferred and are included in the Consolidated Balance
Sheets as Environmental Clean-up Costs.
The federal and state clean-up programs are not expected to interrupt or
diminish Duke Energy's ability to deliver natural gas to customers. Based on
Duke Energy's experience to date and costs incurred for clean-up 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 or financial position.
Air Quality Control. The Clean Air Act Amendments of 1990 require a
two-phase reduction by electric utilities in aggregate annual emissions of
sulfur dioxide and nitrogen oxide by 2000. Duke Energy currently meets all
requirements of Phase I. Duke Energy supports the national objective of
protecting air quality in the most cost-effective manner, and has already
reduced emissions by operating plants efficiently, using nuclear and
hydroelectric generation and implementing various compliance strategies. To
meet Phase II requirements by 2000, Duke Energy's current strategy includes
using low-sulfur coal, purchasing sulfur dioxide emission allowances and
installing low-nitrogen oxide burners and emission monitoring equipment.
Construction activities needed to comply with Phase II requirements are
substantially complete. Additional annual operating expenses of approximately
$25 million for low-sulfur coal premiums, emission allowance purchases and
other compliance activities will occur after 2000. This strategy is contingent
upon developments in future markets for emission allowances, low-sulfur coal,
future regulatory and legislative actions and advances in clean air
technologies.
In October 1998, the EPA issued a final ruling on regional ozone control
which requires revised State Implementation Plans for 22 eastern states and the
District of Columbia. This EPA ruling is being challenged in court by various
states, industry and other interests, including the states of North Carolina
and South Carolina and Duke Energy. Depending on the resolution of this matter,
costs to Duke Energy may range from approximately $100 million to $500 million.
In December 1997, the United Nations held negotiations in Kyoto, Japan to
determine how to achieve worldwide stabilization of greenhouse gas emissions,
including carbon dioxide emissions from fossil-fired generating facilities and
methane from natural gas operations. Further negotiations in November 1998 in
Buenos Aires, Argentina, resulted in a work plan to complete the operational
details of the Kyoto agreement by late 2000. Duke Energy is taking steps to
prepare for possible action on greenhouse gas emissions and has completed a
greenhouse gas emissions inventory. Implications of greenhouse gas emissions
are being integrated into planning processes. Because this matter is in the
early stages of discussion, management cannot estimate the effects on future
consolidated results of operations or financial position.
Litigation and Contingencies. For information concerning litigation and
other commitments and contingencies, see Note 14 to the Consolidated Financial
Statements.
Year 2000 Readiness Program. State of Readiness. Duke Energy initiated its
Year 2000 Readiness Program in 1996 and began a formal review of computer-based
systems and devices that are used in its business operations both domestically
and internationally. These systems and devices include customer information,
financial, materials management and personnel systems; as well as components of
natural gas production, gathering, processing and transmission, and electric
generation, distribution and transmission.
Duke Energy is using a three-phase approach to address year 2000 issues:
1) inventory and preliminary assessment of computer systems, equipment and
devices; 2) detailed assessment and remediation planning; and 3) conversion,
testing and contingency planning. Duke Energy is employing a combination of
systems repair and planned systems replacement activities to achieve year 2000
readiness for its business and process control systems, equipment and devices.
Duke Energy has substantially completed the first two phases throughout its
business operations, and is in various stages of the third and final phase.
Duke Energy's goal is to have its critical systems, equipment and devices year
2000 ready by mid-1999. Business acquisitions routinely involve an analysis of
year 2000 readiness and are incorporated into the overall program as necessary.
Duke Energy is actively evaluating and tracking year 2000 readiness of
external third parties with which it has a material relationship. Such third
parties include vendors, customers, U.S. governmental agencies, foreign
governments and agencies, and other business associates. While the year 2000
readiness of third parties cannot be controlled, Duke Energy is attempting to
assess the readiness of third parties and any potential implications to its
operations. Alternate suppliers of critical products, goods and services are
being identified, where necessary.
Costs. Management believes it is devoting the resources necessary to
achieve year 2000 readiness in a timely manner. Current estimates for total
costs of the program, including internal labor as well as incremental costs
such as consulting and
contract costs, are approximately $65 million, of which approximately $41
million had been incurred as of December 31, 1998. These costs exclude
replacement systems that, in addition to being year 2000 ready, provide
significantly enhanced capabilities which will benefit operations in future
periods.
Risks. Management believes it has an effective program in place to manage
the risks associated with the year 2000 issue in a timely manner. Nevertheless,
since it is not possible to anticipate all future outcomes, especially when
third parties are involved, there could be circumstances in which Duke Energy
would temporarily be unable to deliver energy or energy services to its
customers. Management believes that the most reasonably likely worst case
scenario would be small, localized interruptions of service, which likely would
be rapidly restored. In addition, there could be a temporary reduction in
energy needs of customers due to their own year 2000 problems. In the event
that such a scenario occurs, it is not expected to have a material adverse
impact on consolidated results of operations or financial position.
Contingency Plans. Year 2000 contingency planning is currently underway to
assure continuity of business operations for all periods during which year 2000
impacts may occur. Duke Energy is participating in multiple industry efforts to
assure effective year 2000 contingency plans, and intends to complete its own
year 2000 contingency plans by mid-1999. These plans address various year 2000
risk scenarios that cross departmental, business unit and industry lines as
well as specific risks from various internal and external sources, including
supplier readiness.
Based on assessments completed to date and compliance plans in process,
management believes that year 2000 issues, including the cost of making
critical systems, equipment and devices ready, will not have a material adverse
effect on Duke Energy's business operation or consolidated results of
operations or financial position. Nevertheless, achieving year 2000 readiness
is subject to risks and uncertainties, including those described above. While
management believes the possibility is remote, if Duke Energy's internal
systems, or the internal systems of external parties, fail to achieve year 2000
readiness in a timely manner, Duke Energy's business, consolidated results of
operations or financial condition could be adversely affected.
New Accounting Standard. In September 1998, Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," was issued. Duke Energy is required to adopt this standard
by January 1, 2000. SFAS No. 133 requires that all derivatives be recognized as
either assets or liabilities and measured at fair value, and it defines the
accounting for changes in the fair value of the derivatives depending on the
intended use of the derviative. Duke Energy is currently reviewing the expected
impact of SFAS No. 133 on consolidated results of operations and financial
position.
Subsequent Event. On February 18, 1999, Duke Energy announced its intent
to make a concurrent cash tender offer in Chilean pesos in Chile and the United
States for 51% of the outstanding shares of Endesa-Chile. The estimated total
cash outlay is approximately $2.1 billion based on current exchange rates. The
offer will be contingent upon, among other things, certain Endesa-Chile
shareholder approvals. If all approvals are obtained, the transactions are
expected to be completed during the second quarter of 1999. Endesa-Chile
controls and operates 10,247 megawatts of generating capacity in Argentina,
Brazil, Chile, Colombia and Peru.
Forward-Looking Statements. From time to time, Duke Energy may make
statements regarding its 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. Factors that could cause actual
achievements and events to differ materially from those expressed or implied in
such forward-looking statements include state and federal legislative and
regulatory initiatives that affect cost and investment recovery, have an impact
on rate structures and affect the speed and degree to 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 and interest 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; growth in opportunities for Duke Energy's business units;
achievement of year 2000 readiness; and the effect of accounting policies
issued periodically by accounting standard-setting bodies.